IR 05000369/1987026
| ML20238F578 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 09/03/1987 |
| From: | Lawyer L, Oconnor T, Shymlock M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20238F548 | List: |
| References | |
| 50-369-87-26, 50-370-87-26, NUDOCS 8709160231 | |
| Download: ML20238F578 (46) | |
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET, N.W.,
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ATLANTA, GEORGI A 30323
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.IteportNos.: 50-369/87-26'and 50-370/87-26 Licensee: Duke Power Company
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422 South Church Street
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' Charlotte,-NC 28242;
Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9'and NPF-17 Facility Name: :McGuire 1 and 2 I
Inspection' Conducted: August 3-1987 I
Inspectors:
Wd
L. L. Lawyer ReadtorEngneer ~
D' ate Signed
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Team Leader rd adb
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Yv/97 T. J. O'Co p, Leader
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Reactor Engineer-Date Signed i
Assistant Team
-i Team Members: ME S. Lewis A.'R.-Long
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P. B. Moore l
D. J. Nelson M. B. Shymlock Approved;by:
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M.'B'. Shymlock, Chief Date Signed Operational Programs Section Division of Reactor Safety SUMMARY Scope:
This routine, announced inspection involved the review of corrective
' actions for previous findings in the area of maintenance, operations and training.
Additionally, a reactive inspection was conducted in the area of the ' Unit 1, Train A, Diesel Generator inoperability event that occurred between July 26 and July 30, 1987.
This reactive inspection consisted of a-review of -- the circumstances ' surrounding the event including reviews of associated procedures, logs, charts, and interviews with nuclear equipment operators and licensed operators.
..Results:
Two violations were identified.
(Failure to establish and implement procedures; see paragraph 3, and failure to implement approved procedures governing excessive overtime; see paragraph 5.a)
B709160231 870910
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PDR ADOCK 05000369'
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r REPORT DETAILS 1.
Persons Contacted Licensee Employees:
- N. G. Atherton, Compliance, Nuclear Production Specialist III
- B. Hamilton, Technical Services, Superintendent
- G. E. Singletary, I&E, Nuclear Production Engineer
- A. L. Beaver, Operations, Engineer
- G.' Gilbert, Operations, Engineer
- D. McGinnis, Production Training Department, Director Operations Training
- B. Griffin, Production Training Department, Senior Instructor
- P. B. Nardoci, Compliance, Associate Engineer
- S. LeRoy, General Office Licensing, Technical Specialist II D. J. Rains, Superintendent of Maintenance M. C. Maston. Support Technician, Operations J. L. Freeze, Production Specialist, I&E Other selected operations personnel NRC Resident Inspectors:
W. Orders, Senior Resident Inspector
- S. Guenther, Resident Inspector
- Attended exit interview 2.
Exit Interview
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The inspection scope and findings were summarized on August 7, 1987, with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection findings. No dissenting comments were received from the licensee.
A list of system abbreviations can be found in the last paragraph of this report.
(Open) Violation (VIO) 369, 370/87-26-01: Failure to Comply with Technical Specifications and Procedures in area of Excessive Overtime.
(see paragraph 5.a)
(0 pen) VIO 369/87-26-02:
Violations Pertaining to Diesel Generator IA
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Inoperability Coupled with Configuration Control and Shift Turnover. (see
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paragraph 3)
(Closed) VIO 369/84-34-01 & 370/84-31-01: Failure to Adequately Calculate the Calibration Set Point for the Upper Head Injection (UHI) Tank Level Instrumentation.
(see paragraph 4.a)
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- (Closed). " VIO. 369/84-34-02: Failure to Provide Appropriate. Procedural
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Acceptance Cri.teria Necessary to1 Ensure that Unit: 1. UHI Accumulator.
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~ Syste'm Differential Pressure Instruments were Correctly ' Installed.
(see
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' paragraph.4 b).
Kb (Closed) ' VIO - 369/84-34-03:. Failure to Perform 'a ~ Functional Test which
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Lwould Demonstrate that the UHI Accumulator-would Function. Satisfactorily Fo110 wing' Replacement off VHI Accumulator Differential Pressure Instruments.
(see' paragraph 4.c)
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(Closed): Unresolved : Item (UNR) 369/84-34-04. & 370/84-31-02:. Inspector ~
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Concerns Pertaining to the UHI Accumulator being out of Specification on l
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Water Chemistry.
(see paragraph 4.d)-
(Closed) UNR 369/84-34-05 & 370/84-31-03: Inspector Concerns Pertaining Lto the Gas Accumulation in the Reference Leg of the -UHI level'
Instrumentation.
(see paragraph 4.e).
(Closed) UNR 369/85-12-01 & 370/85-13-01: Inspector Concerns Pertaining to the Participation of the Licensee's Staff 'in ' the Licensed Operator Requalification Training Program.
(see. paragraph 4.f)
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'(Closed) UNR 369/85-12-07 & 370/85-13-07: Inspector Concerns Pertaining L,
to. a Licensed 10perator's Application ' not Accurately Reflecting the Training Time Actually Complete'd.- (see paragraph 4.g)
(Closed) VIO 370/85-29-01: Five Examples of. Failure to Follow Procedures on Cold Leg Accumulator Level Transmitter Maintenance.
(see paragraph 4.h)'
(Closed) VIO 369/85-38-01 &'370/85-39-01: Failure to Adequately Perform Preoperational Test on Control Room Chiller.
(see paragraph 4.1)
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(Closed) VIO 369/85-38-02 & 370/85-39-02: Failure to Implement and Maintain Procedures.
(see paragraph 4.j)
(Closed) VIO 369/85-38-03 & 370/85-39-03: Failure to Adequately Establish and Maintain the Operability of the Station's Nuclear Service Water System and the Performance of an Inadequate 10 CFR 50.59 Evaluation.
(see paragraph 4.k)
(Closed) VIO 369/85-38-04 & 370/85-39-04:
Failure to Perform a 10 CFR 50.59 Evaluation on Degraded Equipment.
(see paragraph 4.1)
(Closed) VIO 369/85-38-05 & 370/85-39-05:
Failure to Identify and
~ Correct Conditions Adverse to Quality as Required by 10 CFR 50 Appendix B Criterion XVI.
(see paragraph 4.m)
(Clo' sed) UNR 369/85-38-06 & 370/85-39-06:
NRC Foilow-up of Licensee Response of April 25, 1986.
(see paragraph 4.n)
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-(Closed) VIO 369/85-45-01: Inadequate Post Trip Review Relative to the Reactor Trip and Safety Injection on Unit 1 of November 2,1985.
(see
' paragraph 4.0)
(Closed) Inspector Followup Item (IFI) 369/81-39-02: Inspector Concerns Pertaining to Overtime Restrictions.
(see paragraph 5.a)
(Closed) IFI 369/81-39-04: Resolution of Failure to Meet Loss of Offsite Power Test Acceptance Criteria.
(see paragraph 5.b)
(Closed) IFI 369/81-39-05: Safety Injections' and Reactor Trip Caused by Problems with Instrument and Electronics (IAE) Procedures (see paragraph 5.c)
(Closed) IFI 369/81-39-07: Inspector Concerns Pertaining to Personnel
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leaving the Controlled Area without being Monitored for Radiation. (see paragraph 5.d)
(Closed) IFI 369/84-34-06 & 370/84-31-04: Inspector Concerns Pertaining to the Calibration of Differential Pressure Transmitters. (see paragraph 5, ~e )
(Closed) IFI 369/85-OL-02: Inspector Concerns Pertaining to Inaccuracies in Licensed Operator Lesson Plans.
(see paragraph'5.f)
(Closed) IFI 369/85-12-02 & 370/85-13-02: Inspector Concerns Pertaining to the Participation of Backup Licensed Operators in the Licensed Operator Requalification Training Program.
(see paragraph 5.g)
(Closed) IFI 369/85-12-03 & 370/85-13-03: Inspector Concerns Pertaining to Lecture Atteridance Records.
(see paragraph 5.h)
(Closed) IFI 369/85-12-04 & 370/85-13-04: Inspector Concerns Pertaining to the Completion of the Operational Review Program.
(see paragraph 5.1)
(Closed) IFI 369/85-12-05 & 370/85-13-05: Inspector Concerns Pertaining to the Licensee's Administrative Requirements for Lecture Attendance being Completed via the Operational Review Program.
(see paragraph 5.j)
(Closed) IFI 369, 370/86-22-01: Inspector Concerns Pertaining to the Licensee's Ability to Retrieve Training Records.
(see paragraph 5.k)
(Closed) IFI 369, 370/86-22-02: Inspector Concerns Pertaining to the Regrading of Requalification Examinations.
(see paragraph 5.1)
(Closed) IFI 369, 370/86-22-03: Inspector Concerns Pertaining to the Training Provided to Licensed Operators on the Technical Specifications.
(see paragraph 5.m)
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(Closed) IFI 369, 370/86-22-04: Inspector Concerns Pertaining'to Lecture Attendance and Contact Hours for' Requalification Training.
(see
paragraph 5.n)
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The. licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during'this inspection.
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Emergency. Diesel Generator Inoperability'(93702)
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A reactive inspection was conducted to review the circumstances
surrounding the Unit 1, Train A, Emergency Diesel Generator (D/G 1A)
inoperability which occurred between July 26 'and July 30, 1987.
D/G 1A and associated Train
"A"' safety related equipment were removed from service to support plant maintenance activities. Following completion of these maintenance activities, D/G 1A and associated Train
"A". safety related equipment should have been fully-restored to an operable status.
However, a number of factors contributed to a failure to perform a full restoration of D/G 1A and associated Train "A" safety related equipment.
This inspection' centered on the associated sequence of events,' including operator actions and procedures utilized by operators to accomplish those actions.
Evaluations were'.. made-by the inspectors to ascertain.
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applicability of the inspection findings to overall plant operations.
On. July 26, 1987, at approximately 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br />, Removal and Restoration (R&R) No.17-169, was issued by the ' Unit -Supervisor to the-Nuclear Equipment Operators (NE0s) to remove the Unit 1, Train
"A",
Nuclear Service Water Cooling, Pump (RN-1A) and associated equipment from service
.to permit RN 1A oil-sampling. The following ass'ociated Train "A" safety related equipment was. removed from service to prevent operation of this equipment'without cooling water (Cooling water is supplied by RN 1A):
Containment Spray System (NS)
Component Cooling System (KC)
Boration Flow Path, Chemical and Volume Control System (NV)
Charging Pump, Chemical and Volume Control System (NV)
Emergency Core Cooling System (ECCS)
Auxiliary Feedwater System (CA)
Control Area Ventilation and Chilled Water System (VC/YC)
Diesel Generator (D/G 1A)
Additionally, removal of D/G 1A from service placed the following Train
"A" equipment in 6 technically inoperable status due to the unavailability of ermtrgency power source:
Auxiliary Feedwater System (CA)
Control' Area Ventilation and Chilled Water System (VC/YC)
Safety Injection System (NI)
Residual Heat Removal System (ND)
Chemical and Volume Control System (NV)
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Component Cooling System (KC)
Nuclear Service Water System (RN)
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Auxiliary Building Ventilation-System (VA)
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Annulus: Ventilation System (VE)
Containment' Spray. System (NS)
Hydrogen Skimmer and Containment' Air Return System (VX)
Containment Isolation-Hydrogen Recombiners-Pressurizer Heater Group A 600 V. Essential Power.
Hydrogen Mitigation, Hydrogen Monitors.
Vital Battery Charger On July 27, 1987, the.' maintenance staff completed the oil sampling activities. Two NEOs were directed' to restore RN-1A and its' associated ~
safety related equipment' as listed on R&R 17-169 (via the restoration-
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The -NE0s reported control power restored to all components and R&R 17-169 completed. At approximately 0500, the control room declared 'all. equipment associated with ~ R&R 17-169 operable, despite the fact that control-power had not been restored to D/G 1A, As a result of-the error,' the D/G' 1A control power breaker remained open, rendering the D/G 1A and associated Train "A" safety related equipment inoperable.
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The subject. D/G 1A control power breaker provides 125 volt DC power to start the diesel generator.
This control power is not associated with the diesel. generator output breaker.
(At this time, D/G.1A had been inoperable for 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />)
Om July, 27, 1987,~ at approximately-1430, Train
"B" of the auxiliary
- feedwater system was' declared inoperable due to the nuclear service water supply valves IRN-162B ' and ICA-ISB exceeding
- their streke time limits during surveillance testing.
This action placed the
"B" motor driven auxiliary feedwater pump into an. inoperable status, thereby causing the plant. to enter the action statement for the Limiting Condition of
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Operation (LCO) ' for. auxiliary.feedwater system operability. The Action Statement requires the. plant to restore the pump to an operable status
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within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and
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in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
With D/G 1A out of service and unable to provide emergency power to Train
"A" auxiliary feedwater components (nuclear service water supply valves, motor driven pump, etc.), Train "A" of auxiliary feedwater is forced into an inoperable status.
In addition, as a result of Trains "A"
& "B" of nuclear service water being inoperable, all three auxiliary feedwater pumps are placed into an inoperable status.
The action statement associated with three' auxiliary feedwater pumps inoperable requires the L
plant be in HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the
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following six hours.
Additionally, immediate corrective action is I
required to restore at least one auxiliary feedwater pump to operable
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( At this time, D/G 1A had been inoperable for 21.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />)
On July 28, 1987, at approximately 1415, Train
"B" of the auxiliary
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I feedwater system was declared operable upon successful completion of i
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i maintenance activities associated with the stroke time testing of the nuclear service water system supply valves.
(At this time, D/G 1A had been. inoperable for 44.25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />)
On July 29,.1987, a Reactor Operator (RO) observed that the D/G 1A
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control switch - (control room) lights (red / green) were not illuminated
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(during. five previous shif t turnovers, this observation had not been made, nor had any corrective action been taken).
Illumination of the D/G 1A control switch light (red / green) indicates that 125 volt DC control power is available to start D/G 1A.
Additionally, the R0 observed from the indication lights on the Unit 1 Bypass Panel that D/G 1A was inoperable.
Bypass / inoperable panels are designed to assist licensed operators in assessing the ramifications of each bypassed or inoperable component, and to provide automatic indication of the bypass or of the inoperability of each redundant portion of a system that
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performs a function important to safety. Despite the multiple indicators available to him, the R0 assumed the switch to be faulty and initiated a work request to " repair so off light will illuminate." The operator did not attempt to verify the existence of control power to the D/G 1A switch.
(At this time, D/G 1A had been inoperable for 69 hours7.986111e-4 days <br />0.0192 hours <br />1.140873e-4 weeks <br />2.62545e-5 months <br />)
On July 30, 1987, at approximately 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br />, R&R 17-185 was issued to remove RN-1A from service to support the rodding out of the motor cooler heat exchanger. Again, additional safety related equipment was removed from service to prevent operation without cooling water supplied via RN-1A.
While removing the equipment specified on R&R 17-185 from service, the NE0s discovered the D/G 1A control power breaker in the open
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(deenergized) position.
The NE0s reported this finding to the control room at approximately 0530 and continued removing the remaining equipment
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from service. The control power breaker for D/G 1A was still not closed (energized) at this time.
At this time, D/G 1A has been in an inoperable status for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. When a diesel generator is placed into an inoperable status, the plant is required to enter the Action Statement for the LC0 under A.C.
Power System operability.
The Action Statement requires the plant to demonstrate the operability of the AC offsite sources by performing Surveillance Requirement 4.8.1.1.la within one hour and at least once per
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eight hours thereafter.
Additionally, the diesel is required to be
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returned to an operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Review of Shift Supervisor and R0 logs do not indicate that steps were taken to initiate a plant shutdown, nor do they indicate that
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the plant demonstrated the operability of the AC offsite sources.
On July 30, 1987, at approximately 0820, the Shift Supervisor made the i
decision that safety tags would be pulled from nuclear service water pump RN-1A, and R&R 17-185 cleared.
Upon clearance of R&R 17-185, an
operability test would be performed on D/G 1A and D/G 18.
Operability
tests were completed at 1230 for D/G 1A (at this time, D/G 1A had been f
inoperable for 90.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />) and at 1525 for D/G 18.
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The aforementioned sequence of' events resulted in D/G 1A being out of service for greater than-72 hours, leaving the Train "A" emergency bus without an ' emergency power supply.
Unit I did not commence plant shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to reach a HOT STANDBY condition as required.
In addition, full power operations were conducted with all auxiliary feedwater pumps in an inoperable status for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The circumstances surrounding the D/G 1A inoperability, the apparent lack of g
remedial action which transpired between 0530 and 0820 hours0.00949 days <br />0.228 hours <br />0.00136 weeks <br />3.1201e-4 months <br /> on July 30, 1987, and the failure of five shift turnovers to recognize apparent and important control room indications of equipment inoperability are a cause for concern.
As noted above, RN 1A was removed from service on July 26, 1987. Removal was accomplished via Operations Management Procedure (OMP) 2-17, Tagout/
Removal and Restoration' (R&R) Procedure, Rev. O.
This procedure explains how the Tagout (R&R) Record Sheet shall be used by the Operations Group
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to remove equipment from service for maintenance or safety considerations j
and return the equipment to service.
Station Dir'ective (SD) 3.1,19, i
Safety Tags, prescribes those conditions which warrant the use of red or white tags. Red tags are utilized for personnel safety. Red tags are to be attached to.any component, the operation of which could cause personnel in. jury. White tags are to be used for material or equipment protection.
White tags are to be attached to any component, the operation of which could cause material'or equipment damage.
Review of the event indicates that operations-personnel were not utilizing tagging procedures designed to assist in the control of equipment removed from service. Review of R&R 17-169 revealed that only the equipment actually being worked on (RN 1A) received a red tag.
Equipment removed from service for equipment protection only was not tagged with white tags.
This has been common practice at McGuire for some time'according to station personnel.
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Step 6.1.L of OMP 2-17 delineates the requirements for describing equipment to be removed from service. The procedure requires the name of the specific breaker, switch, or other device to be listed when being tagged or removed from service.
A specific device (breaker number) was not listed for the D/G 1A control power breaker (nor is there a specific identifier for this breaker). For equipment not being safety tagged, the location is also to be listed.
Review of R&R 17-169 revealed that equipment which was not safety tagged, did not have the location of the device to be removed listed.
Under the specific responsibilities section of SD 3.1.19, breakers being tagged out should have the locations written on the back of the tag stub.
The safety related equipment removed from service under R&R 17-169 for equipment protection did not utilize white safety tags.
Use of white safety tags would have provided operations personnel with additional direction for the proper removal and restoration of equipment. Under the i
implementation section of SD 3.1.19, a tag sticker should be placed on
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tagged.
The : safety related equipment removed from service ' under R&R 17-169 did not utilize tag : stickers. Tag stickers placed in the control room would have assisted the R0s in ' identifying D/G '1A as being in an inoperable status.
InterviewsL with licensed personnel indicate. a lack ' of knowledge. in regards to the R&R procedure, OMP 2-17.
The Shift Supervisor who signed'
i R&R'17-169 in the " tag ordered removed" block stated that a signature in
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this block was a release to perform the work.
The shift supervisor was
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specifically asked' whether, in the event the NE0 filled out the." return position" column, he.was expected to review each entry to determine its accuracy before signing the " tag ordered removed" block, to which he stated, "no, it was his giving' permission to perform - the work.". Step 6.3.E of OMP 2-17 states that the Shif.t Supervisor or Assistant Shift Supervisor shall sign the " tag ordered removed" block indicating all work on listed work orders' is complete, and that restoration will place the equipment in the desired position.
The importance of this step is significant when reviewed in conjunction.with R&R 17-169. The " return position". originally contained two incorrect or ambiguous instructions:
1)" installed" for a isolation valve which should have been " locked open,"
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and-2) " installed" for the D/G 1A control power breaker which should have been " closed."
The " return position" for the isolation valve was subsequently corrected ' by the NEO, without approval from the Shift Supervisor.
As noted above, RN 1A was returned to service on July 27, 1987. As a point of clarification it should be noted that R&R 17-169. listed the D/G 1A control power breaker in the "open" position vice having fuses
" removed" as was required with other electrical components under R&R 17-'169.
Additionally, the D/G 1A control power breaker was the only electrical ' component not physically located in the 6.9 kv breaker room.
Section 6.3, Restoration Entries, of OMP 2-17, specifies the various requi ements to be met in order to. ensure that equipment is correctly restori.d to an operable status.
Sequence numbers should be assigned and shall indicate the order in which equipment is to be returned to service.
Sequence numbers for situations not requiring a sequence shall be indicated on the R&R by placing "N/A" in the " SEQ.
NO." block.
The individual performing the restoration shall sign the original R&R indicating he has removed the safety tag (if issued) and placed the equipment listed on that line in the return position indicated.
For components requiring independent verification, OMP 2-17 requires that a second,~ completely independent verification of the return alignment shall be performed per OMP 1-6, Independent Verification.
The individual performing independent verification shall initial the original R&R. This is consistent with NUREG-0737, Item I.C.6, Independent Verification, which requires the implementation of procedures to verity the correct position of operating components.
Intervicws were conducted with the NE0s who performed R&R 17-169 restoration. The NE0s stated that they worked together, both installing
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. fuses.'in.the electrical.' breaker panels ' until.all. ' control power lights were illuminated. Having installed.all ofL the. fuses and noting that' all theilights.were illuminated, onei NEO initialed the " tag removed" blocks,
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and, the other NEO initialed the " independent verification" blocks.for those components-whose return position.was " installed." The restoration-of equipment was not performed by one individual. and-verified to-be in
.the correct position by a second individual completely independent of the
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S.ignatures on..R&R -17-169 do not accurately reflect which individual-performed the restoration..or the independent verification - function.
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Neither NE0 could recall,which components they actually restored..The restoration was not performed according to the sequence as specified by R&R 17-169, but rather performed in a random manner.
Each component was not signed off upon restoration or verification, but rather the entire sheet was signed off at one time.
. Individual components were not correlated to R&R 17-169,- but rather all available control power fuses were installed in a random manner, resulting int more Litems - being certified as restored and as being independently verified than was actually the case.. Restoration activities conducted in this manner could allow the' restoration of equipment unrelated to the subject R&R.
These actions resulted_ in the control power for the D/G 1A output breaker, located. adjacent ' to ' control power for equipment removed from service, to be mistaken for the D/G 1A control power (breaker).
The scenario as
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described above raises'a concern pertaining to the licensee's training'of licensed and non-licensed operators in the area of removal and restoration procedures, and in particular the subject of-independent verification.
Performing restorations according to the sequence specified, with one-individual performing the restoration and a second performing the independent verification, in conjunction with white safety tags, could.significantly decrease the potential for inoperability problems associated with. operator error.
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D/G 1A was inoperable for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> starting at 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> on July 26, 1987.
During this time period numerous shift turnovers were performed according to Operations Management Procedure (OMP) 2-2, Shift Turnover, Rev.2, dated May 29, 1987.
This raises concern over the adequacy of shift turnover, the training licensed operators receive in relation to shift turnover responsibilities and their understanding of control board indications.
OMP 2-2 requires each shift turnover to review the control board and pay particular attention to the Unit Bypass panel and control board indicating lights (burned out bulbs).
When control power is available to D/G 1A start /stop switch either the "on" (red) or "off" (green) indicating lamp is illuminated.
i; Interviews with various R0s delineated the steps to be taken upon l'
discovery of no illumination for this type of switch. The first step to be taken is to determine if the bulbs are burned out.
Upon verification that the bulbs are not defective, control power must be verified to the switch. Five shift turnovers occurred without detection of the degraded b
condition of the D/G 1A start /stop switch.
At approximately 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br />
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I on July 29, 1987, an R0 issued a ' work request for D/G 1A start /stop switch to " repair so off light will illuminate." The R0 did not verify the status of control. power to D/G 1A. The R0 issued the work request based on the following information: 1)'new bulb < placed into the switch failed to illuminate, 2) the annunciator "125 VDC D/G Control PWR SYS
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Trouble" was not illuminated, and 3) his mistaken belief that the Unit 1 Bypass was providing " faulty" indication that D/G 1A was inoperable.
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The F1'?5 VDC D/G Control PWR SYS Trouble" annunciator provides indication of degr.'ded conditions of the power supply (batteries / battery chargers)
for D/G 1A control power and receives its input up stream of the control power breaker, and therefore, would not alarm upon opening of the control
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power breaker.
The D/G 1A INOP Unit 1 Bypass panel indicator was
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considered " faulty" by the R0.
The R0 and Shift Supervisor logs as well as the Nuclear Control Operator Turnover Checklist do not document the j
D/G 1A INOP Unit 1 Bypass indicator as being "hulty" during the subject
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time period.
The D/G 1A IN0P Unit 1 Bypass < panel indicator was illuminated during the subject time period.
Iliumiution of the D/G 1A IN0p indicator results from several possible causo;, including:
RN.1A Bypass (RN Pump Inoperable)
Emergency Stop Not Reset Engine overspeed, Low Lube Oil Shutdown Relays Not Reset 125 VDC D/G Control Power System Trouble Loss Of DC Control Power i
The RO who initiated the work request on the D/G 1A start /stop switch made no attempt to verify any of the above mentioned possible causes for the D/G 1A INOP indicator.being illuminated, more specifically the R0 did not verify that control power was available tc the 0/G 1A start /stop switch. The fact that the R0 made no attempt to verify control power availability raises a concern pertaining to the licensed operators training in the area of control power and its indication, or lack thereof, in the control room. The adequacy of licensed operator training i
in the area of control board walkdown is questionable,' especially in l
light of the fact that six shift turnovers occurred without proper corrective action being taken in response to control room indications that D/G 1A was inoperable.
I In addition, there are concerns regarding the licensee's administrative l
control over the D/G 1A control power breaker.
System line up shnets do q
not ensure correct alignment of the D/G 1A control power breaker.
D/G
operability procedures do not ensure correct aligt, ment of the posit.fon of the D/G 1A control power breaker.
Technical Specification 3.8.1.1 requires that two physically independent
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circuits between the offsite transmission network and the onsite
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l essential auxiliary power system, and two separate and independent diesel
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l generators be operable in Modes 1,2,3, and 4.
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LTechnicalISpecification' 3.5.2 Trequires : that two independent Emergency
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W Core Cooling Fystems ;(ECCS) subsystems be operable. in Modes 1, 2, and 3.
The LCO actionfstatement requires that with one inoperable.ECCS subsystem
'the licensee' must; restore the. inoperable. subsystem.to operable status within' 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at-least HOT STANDBY within the next six ' hours g
and in HOT-SHUTDOWN within the following six hours.
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Technical: Specification 3-7.1.2 requires that at least three independent
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steam generator auxiliary feedwater pumps and associated flow' paths be:
operable.'
The LCO action statement - requires that if three ' auxiliary f feedwater pumps are inoperable, the licensee 'must be in HOT ' STANDBY
'within. six hours and in HOT SHUTDOWN vithin the next six ' hours.
Additionally, immediate. corrective action to restore' at least one auxiliary feedwater pump to operable status.is to be initiated.
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. Technical Specifications.6.8.1 requires that written procedures shall be x,
established,' and implemented for activities recommended in Appendix A of 3,
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Regulatory Guide 1,33.
Appendix A recommends, in part, that procedures '
for the operation'of safety related systems should be established.
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Additionally; Technical : Specification 6.8.1 requires that written
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% commended in NUREG-0737, Item I.C.6, Independent Verification; Item 1.C:5 : requires the implementation of procedures to verify the correct performance of' operating activities.
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As noted above, from 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> on July 26,1987, until 1230, hours on
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- July 30, 1987, (90.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />), while in Mode 1, D/G 1A was inoperable and
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unable to be automatically started by. an initiating signal due to the lack of control power.
As noted above, from 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> on July '26,1987, until 1230 hours0.0142 days <br />0.342 hours <br />0.00203 weeks <br />4.68015e-4 months <br /> on
July 30,.1987, (90.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />), while in Mode 1, the A electrical train ECCS subsystem was inoperable due.to the inoperability of D/G 1A.
As noted above, from 1430 hours0.0166 days <br />0.397 hours <br />0.00236 weeks <br />5.44115e-4 months <br /> on July 27, 1987, until 1415 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.384075e-4 months <br /> on July 28, 1987, (23.75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />), while in Mode 1, B Train of the auxiliary i
feedwater system was declared inoperable when suction valves 1RN-162B and ICA-18B failed their stroke time test.
Additionally, the A Train of auxiliary feedwater was inoperable due to the unavailability of D/G 1A.
j The inoperability of the A and B trains of the auxiliary feedwater system
. placed the plant in a condition under which operations continued while
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all three auxiliary feedwater pumps were inoperable.
As..noted above, the licensee did not establish or implement adequate procedures to assure configuration control over D/G 1A, a safety related
system, between July 26, 1987, and July 30,. 1987.
Examples include the si following:
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Six shift turnovers occurred without proper corrective action being
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taken for the lack of control power indication on the D/G 1A start /stop switch, as required by OMP 2-2.
Six shift turnovers occurred without adequate response to the D/G 1A
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INOP indicator being illuminated on the Unit 1 Bypass panel, as required by OMP 2-2.
The Nuclear Equipment Operator (NED) did not restore the ECCS
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equipment in the order specified by R&R 17-169, or according to the requirements of OMP 2-17.
The NE0 did not sign off each component upon restoration as required
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by OMP 2-17, but rather signed off the entire sheet at one time.
The NE0 signed off as restored, one item on R&R 17-169 for which no
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restoration had been performed, thereby, not meeting the requirements of OMP 2-17.
The second NE0 did not perform the independent verification of the
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ECCS equipment in the order specified by R&R 17-169, or according to the requirements of OMP 2-17.
The second NE0 did not sign off each component upon verification of
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restoration as required by OMP 2-17, but rather signed off the entire sheet at one time.
The second NE0 signed off as verified, one item on R&R 17-169 for
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which no restoration had been performed, thereby, not meeting the requirements of OMP 2-17.
The Unit Supervisor did not fill out R&R 17-169 according to OMP
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2-17, thereby providing inaccurate directions to the NE0's.
Inaccuracies include instructions which direct the NE0 to
" installed" vice " locked open" a valve, and " installed" vice
" closed" on the D/G 1A control power breaker.
I R&R 17-169 did not provide an adequate or complete description of
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the the D/G 1A control power breaker for removal or restoration as required by OMP 2-17.
System line up sheets do not align the D/G 1A control power breaker.
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D/G operability procedures do not verify the position of the D/G 1A control power breaker. This lack of administrative control does not meet the requirements of Technical Specification 6.8.1.
These examples of failure to meet Technical Specification Action Statements and establish or implement adequate procedures to control the l
configuration and operation of a safety related system are an apparent I
violation. This item will be tracked as VIO 369/87-26-02, i
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i 369/84-401,b,370/84-31-01:.?ailure to Adequately:
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.(C]osed) VIO e
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Calculateuthe t Calibritihn Seh.- Point for the Upper Head Injection
"1 (UHI) Tank Level Instrumiitat4cn.
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Background:
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iThis violation ' documented the >1' censee's fiilure to accurate 1.W i
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calculatei the~ differential pressure set pointint which the
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- differential: pressure instruments wouli gererate a" valve W closure signal ' for - the. accumulator issMion! valve. Accurate
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calculation of this: set Point ensure's t. hat the proper amount of y'
e ' borated water is'injscted under accideht conditions.
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Resolution.
On (May 13, : IS37, t$ej tlRC notified Duke.Pcler Company (of its
, eacceptance ot"the proposal which requested that the ~ McGuire
$ facility' be relieved of the requirement to maints'n the UHI f'n
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operable status. Accordingly, the McGuire Technical Specifications were amended to permit full power operation with the UHis functionally disabled or physically renoved.
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+ Based' on this information and' the fact that the <UHI is functionaJJ9
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d c'isabled or physically removed, the item is clcsed.
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b; (Closed) 00 ~ 369/84-34-02-: Failu e to Provide Appropriate procedi:ral g
Acceptance Criteria Necessary to Ersure that Unit 1 UHI necumulator System Dif ferential Pressure Instruments were Correctly Installed.
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Background:
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doevme'nked the licensee's failure to provide
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adequate $dinctMdiv insta11ation documents rad /snfiguration s
schema tics withL respbcf to the connadiin ' df Kosemont instrudntation to Usbre that the ' UHI instruments were
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installed ir/ the preter configuration f sr operation.
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On May 13, 1987, the NRC notified Duke Power Ccmpany of its
. acceptance of the proposal which /equested that the McGuire y
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an op'erable status. Accor (.Y, the McGuire lechnical P
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Specifications were amended /@to permitlull power ope"ation with
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the UHI functionally / disabled or physically removed.
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Add [tionally, the licensee committed in their response dated s
March 22, 1985, to revise t number of IAE differential pressure
,rfocedures to include' 'an, appropriately worded statement in the n
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Limit and Precaution section s% ting:
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" Appropriate precautions'should be utilized to insure that high and: low pressure impulse lines are correctly
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installed for proper output from the instrument. Refer as necessary to correct instrument - drawf ng for ' instrumer,t-involved."
A random review of the procedures cited by. the. licensee as
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having. been revised revealed that the' following procedures did not' contain the aforementioned. statement:
IP/0/B/3214/01, approved April.11, 1986, Calibration Procedure For Rosemount
. Models '1151GP, 1151 DP, 1151 HP, and. 1151 AP Pressure x
S Transmitters, IP/0/A/3007/15, approved February 5, 1987, NIS Intermediate Range Detector Saturation Test, IP/0/A/3090/05,.
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approved. December 18,1985, Installation 6nd. Maintenance of Instrument ~Line Fittings.
Nevertheless,. further discussions with the licensee indicated that instrumentation procedures have been revised to incorporate human factors suggestions and that the response ' letter contained typographical errors which listed some procedures incorrectly.
Based on this.information and the fact that the UHI is functionally disabled or physically removed, the item is closed.
c.
(Closed) VIO 369/84-34-03: Failure to Perform a Functional Test which would Demonstratethat the UHI Accumulator would Function Satisfactorily Following Replacement of UHI Accumulator Differential pressure Instruments.
Background:
This violation. documented the licensee's failure to provide adequate post-modification functional testing resulting in the
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failure to detect the incorrect installation of the differentia 1' pressure instruments.
Resolution:
On May 13, 1987, the NRC notified Duke Power Company of its acceptance of the proposal which requested that the McGuire facility be relieved of the requirement to maintain the UHI in L
an operable status. Accordingly, the McGuire Technical l.
Specifications were amended to permit full power opr ation with
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the UHI functionally disabled or physically removed.
Additionally, the licensee has revised Station Directive 4.4.1, Pav 9,
dated July 21, 1987, Processing Nuclear Station Edification (NSMs), to delineate the responsibilities of the engineering staff for determining the applicability of post-modification testing and the development of those procedures as necessary for NSMs.
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B'ased.on this information and the fact that the UHI is functionally
- disabled or physically removed, the' item is closed.
d.~
'(Closed). UNR 369/84-34-04 &'L370/84-31-02:
Inspector Concerns:
Pertaining to -the UHI Accumulator being out of Specification on
Water Chemistry.
- Background
.
This UNR documents inspector concerns pertaining-to the source of nitrogen which caused the' UHI. accumulator to ' exceed the.:
Technical Specification limits on' water chemistry.
Resolution:-
On May -13, 1987, the NRC notified Duke Power Company of its acceptance. of 'the proposal.which. requested that the. McGuire facility be relieved of the requirement to maintain the itHI in an. operable status. Accordingly, the' McGuire Technical Specifications'were amended to permit full power operation with the UHI functionally. disabled or physically removed.
Prior to' the' aforementioned relief, the licensee.-investigated and identified the source of-nitrogen leakage into the UHI system. Appropriate maintenance activities were commenced to correct identified deficiencies.
Based on this information 'and the fact that the UHI is functionally disabled or physically removed, the item is closed.
e.
(Closed) UNR 369/84-34-05 & 370/84-31-03:
Inspector Concerns Pertaining to the Gas Accumulation in' the Reference Leg.of the UHI Level Instrumentation.
Background:
This UNR documents a concern that the licensee should ascertain that gas accumulation in the reference leg is not occurring under normal operating pressure conditions and that gas accumulation and voiding of the reference leg will not occur during UHI injec % ' under accident conditions.
Resolution:
Evaluation by tne licensee regarding this concern was delineated in L%ensee Event Report 369/84-29 which states:
"A review of the instrumentation determined that the upper and lower taps correspond approximately to the top and bottom of the tank.
There is no means of displacing liquid with nitrogen other than out the tank discharge piping.
Therefore, any distribution of nitrogen bubbles within the tank will result in a valid level indication
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-and premature isolation of the injection path cannot
- occur."
On May 13,.1987, - the NRC notified Duke Power Companysof its -
acceptance: of the proposal which. requested.that the McGuire-facility be relieved-of the requirement to maintain the UHI in an-operable stat";. 'Accordingly, 'the McGuire = Technical-Sp'ecifications 'were amended to permit full. power operation with the UHI functionally disabled or physically' removed.
,
Based on 'this information and the fact that the UHI is functionally disabled or physically removed, the item is closed.
f.
(Closed) UNR 369/85-12~01 & 370/85-13-01:
Inspector Concerns Pertaining to the Participation of the Licensee's Staff in the Licensed Operator Requalification Training Program.
Background:
Contrary to-the 10 CFR Part 55.33 and Part 55, Appendix-A -
requirements in effect, licensed operator requalification
. training records _ for four licensed instructors lacked indication of participation in requisite lectures or completion of segment examinations in 1984.
Neither the licensee's 1984 Training Summary nor the. facility's Final Safety Analysis Report-contained provisions allowing exemptions from the-aforementioned lectures and examinations.
This item was considered an unresolved item pending' further evaluation with respect to the NRC policy statement on training and qualifications of nuclear power plant personnel.
Resolution:
A' review of selected training records for. 1986 and 1987
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indicated that licensed instructors participated in required lectures and completed the required examination.
In addition, the licensee notified the NRC by letter dated July 16, 1987, that training instructors will no longer require active licenses.. Instructors will be subject to the licensee's INPO accredited instructor certification program.
The licensee is currently finalizing Standard 310.0, Periodic Training Certified Instructor Requalification, which defines the requalification program for certified operations instructors.
This standard became effective on August 1, 1987.
Instructor certifications are not part of the scope of the recently issued 10 CFR 55.
Based on this information, the item is closed.
g.
(Closed) UNR 369/85-12-07 & 370/85-13-07:
Inspector Concerns Pertaining to a Licensed Operator's Application not Accurately Reflecting the Training Time Actually Completed.
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NRC. Form 398 is used to document ~ the ' application. for an-operator license. candidate or license renewal..The inspector determined during. a review. of selected'.398 forms that discrepancies existed-between the documented weeks of. training -
and; the actual training weeks.
The. licensee -indicated in a-telephone ~ conversation with NRC Region -II personnel that-the identified discrepancy may have been attributed to. including holidays and.SR0 stress management training during -the. period
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under question.
The inspector considered' the item unresolved.
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pending further. review of documentation; supporting the stated cause of the discrepancy.
Resolution:
By reviewing ie training syllabus for the period in question,
'the inspecto jetermined that the discrepancy was, in fact, a
. result of theilicensee inappropriately considering six holidays and one week ' of stress management. training as part of. the calculated training attendance.
This error occurred because-the licensee -calculated training attendance by subtracting the start date.of training from the end date.
The licensee has since revised its method of calculating training attendance by totaling an individual's actual training time'and dividing by 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> to obtain weeks.
The inspector compared selected attendance records against the 398 forms, which document the training durations.
No discrepancies were noted.
. Based on this information, the item is closed.
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h.
(Closed) VIO 370/85-29-01:
Five Examples of Failure to Follow Procedures on Cold Leg Accumulator Level Transmitter Maintenance Licensee letters dated December 12, 1985 and June 13, 1986, provided a response to the Notice of Violation which was considered acceptable by the NRC.
Example a: Quality Control Review of Tubing Tee Replacement.
Background:
Quality Control (QC) had not been provided an opportunity to review a tubing test tee replacement on a cold leg accumulator level transmitter under Work Request 123686 OPS.
Resolution:
i The test tee in question was again replaced in May 1986 to
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ensure and document the required QC involvement.
The inspector reviewed Work Request 65645, and the applicable portions of completed procedure IP/0/A/3090/01, Installation and i
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Maintenance. of Instrument Line Fittings. No problems were identified.
Training 'of' all.I&E' crews cn this ' incident, and on QA/QC
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! requirements when replacing Code 8 fittings, was completed as
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of: : January '13,-
1986. The inspector. reviewed the course
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attendance and:the - training scope as described in a memo dated October 18,.~ 1985 : and a. notice dated November -'22, 1985.
The
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training appeared. adequate.to prevent the. recurrence of the problem.
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The. inspector. concluded that licensee corrective actions _ad'equately addressed:this example of the violation.
Example b:
Calibration J Data Sheet and~ Independent Verification.
' Sheets Missing from Work Request.
Background:
Work request 123686 OPS was. missing la completed calibration data sheet and, independent verification sheet for cold leg accumulator level transmitter maintenance.
The data was recorded in the contaminated area and was probably discarded as contaminated waste.
Resolution:
The instrument was not recalibrates immediately because'
calibration and' independent verification were indicated in the procedure as-having been successfully completed. The NRC approved the licensee's decision not to immediately recalibrates the instrument by accepting the December 19, 1985 response to the-violation.
The' inspector verified that the level transmitters were recalibrates in June 1986 per IP/0/A/3214/04, Calibration Procedure for Rosemount Model 1152 Transmitters.
The inspector concluded the. licensee corrective actions for Example
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b of the violation were adequate.
Example c:
Failure to Follow Procedure When Calibrating a Rosemount Transmitter.
Background:
The licensee failed to complete all of the steps of procedure IP/0/A/3214/04, entitled Calibration Procedure for Rosemount Model 1152 Transmitters, while performing work request 123686.
Step 10.1.7 of the procedure required applying input pressures at approximately 0, 25, 50, 75, and 100 percent of the input range specified for the transmitter.
Because calibration of the transmitters had previously been completed under other work requests earlier in the outage, and there was no reason to suspect the span and linearity of the transmitters, the licensee only applied input pressures to the transmitter at the
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0 and -.100 percent; ranges. ' The. licensee considered 'the work
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bei,ng. performed to be troubleshooting.
Additionally,.:the.11censee used Ja different method' of.
' calibration than that specified; in the ' procedure. Thet calibration reference data and the method ^of calibration were unreviewed and.:a procedure change -was not initiated and approved for this method of calibration.
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Resolution:
Procedure IP/0/A/3214/04 was revised in January 1986 to correct '
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the survey elevations used in the -procedure for calibration reference data, and to allow flexibility when troubleshooting.
AJnote in section 10.0' gives' instruction-to perform procedure.-
steps necessary to meet-acceptance criteria. and complete; the work req ue st',
ana to mark. procedure steps which are not applicable "N/A" on the Data Sheet.
The inspector concluded that-the coirective actions for Example c of the-violation were adequate.
Example d: ' Failure to Identify Errors in Procedure to Calibrate Cold Leg Accumulator Level Transmitters.
Background:
The. review per Station Directive 4.2.1 of Procedure IP/0/B/3000/03, : Revision 15 did not identify that certain calibration data for Unit 2 Cold Leg Accumulator Level-Transmitters was either deleted or incorrect.
Consequently, when performing work requests 023345 PM through 023352 PM,'the level transmitters were calibrated to incorrect data.
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Resolution:
The inspector verified.that Procedure IP/0/B/3000/03,
.Accmulator Tank level calibration, was corrected.
The NRC accepted the licensee's position in the supplemental response to the Notice of Violation that the inadequate review was an isolated case for which no further action would be required. A two year procedure review program was implemeded per procedure APM 4.2 to verify the adequacy of maintenance procedures.
The inspector concluded that the licensee corrective actions for Example d of the violation were adequate.
Example e:
Functional Verification and Documentation of Transmitter Maintenance.
Background:
The licensee did not conduct and document a required functional i
verification of transmitters on Work Request 123686 because the I
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t planner had indicated on the work request form that functional verification was not required.
Resolution:
The inspector verified that Work Request 050252, completed June 25, 1987, had functional verification.
Additionally, the
inspector verified that corrections have been made to the
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computer file from which the Preventive Maintenance work
!
requests are printed to designate functional verifications as being required.
Licensee corrective actions for Example 3 of the violation were adequate.
The inspector concluded that the licensee had corrected the previous problem and. developed corrective action to preclude recurrence of similar problems.
Corrective actions stated-in the licensee response have been implemented. The item is therefore closed.
Note:
The following violations are be'ing dealt with as they were originally. written in IE report 50-369/85-38, 50-370/85-39.
Subsequent enforcement action regrouped several of the violations and this is detailed in a Notice of Violation and Imposition of Civil Penalty from J.
Nelson Grace, Regional Administrator to Hal B. Tucker, Vice President, Nuclear Production Department, Duke Power Company, dated March 6, 1987.
i.
(Closed) VIO 369/85-38-01 & 370/85-39-01: Failure to Adequately perform Preoperational Test on Control Room Chiller.
Background:
After addressing both NRC and DPC concerns regarding the
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desired RN flow test system configuration, the licensee realized the preoperational test configuration had not tested the system under the design basis accident configuration. This design basis accident configuration requires both units to -
supply their Service Water (RN) loads from the Standby Nuclear Service Water Pond (SNSWP) while one unit experiences a LOCA and the other a Blackout.
This represents a violation of 10 CFR 50, Appendix B, Criterion XI, which requires that a test program be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service
.
is identified and performed in accordance with written test j
procedures which incorporate the requirements and acceptance f
limits contained in applicable design documents.
'
Resolution:
The licensee has implemented a heat exchanger performance h
monitoring program that addresses the above stated violation as l
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well. as manyL of the other violations contained in the subject report.
The inspector. reviewed. - procedures PT/1/A/4403/07, changes 0 to 0, RN. Train 1A Flow Balance, and PT/2/A/4403/07,-
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changes ~ 0 to: 0,; RN, train 2A flow balance.
These proceduresc idetailedifor their respective. trains the. methods, used 'and -
results obtai,ned. in-verifying' that various RN train essential-heat exchangers and motor cooler flow rates meet the minimum design flowrates when aligned to the containment spray-protection signal configuration.
This is the : configuration described for the design basis accident. _This flow balance is
conducted : quarterly and adequately. addresses the_
concern
,
regarding the alignment of both unit RN systems to the SNSWP while one experiences a,LOCA and. the other a blackout.
One-di screpancy.. was noted however in that enclosure 13.2, the design. flowrate value for RN to VC (Control, Cable, and i
Equipment Room Air Conditioning Condenser) Train "A" Flowrate was lis.ted at 775 gpm and not 789 gpm as~specified'in the FSAR.
The. licensee explained that the value of 775 gpm was.taken from vendor recommendations and that the 789 gpm-value was from the original design documents ' for the plant that were formulated prior to having the vendor information.
The li.censee also stated that a change to the FSAR would be forthcoming to correct this. discrepancy.
The inspector also reviewed PT/0/A/4457/03, VC/YC Condenser-A delta e Performance Test, changes 0 to 0.
The data gathered
'from this procedure is used _ to determine the extent of RN fouling of the VC/YC train A condenser.
This procedure is performed semiannually and it adequately addresses the concern of possible fouling in the condenser by monitoring and trending the data obtained.
Bused on this information, the item is closed.
j.
(Closed) VIO 369/85-38-02 & 370/85-39-02: Failure to Implement and Maintain Procedures.
Background:
To assure minimum RN component flows, including adequate flow to the containment spray heat exchangers during LOCA conditions, the normally throttled valves associated with each RN component were required to be set during preoperational testing of the RN system.
These throttled positions established during preoperational testing were to be incorporated into operating and surveillance procedures to protect these throttled settings during future operations.
It was noted that, in some cases and particularly for Unit 1, the throttled valve positions listed in the licensees RN operating i
procedures and in their locked valve verification procedures j
were not consistent with earlier preoperational as-left data.
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The licensee acknowledged these discrepancies and committed to revise the operational procedures to meet those valve settings established during recent 1985 and 1986 RN flow testing.
In rr.spu..se to IE Bulletin 81-03 which addressed the potential fould.ng of safety related heat exchangers by rhm and shell debris, the licensee committed to the NRC to monitor two RN supplied heat exchangers on a quarterly basis.
The licensee also stated that if significant fouling is detected on these heat exchangers, other heat exchangers in the RN system will be inspected.
The licensee performed their monitoring under procedure PT/1/A/4403/04, RN supplied Heat Exchanger Performance Monitoring.
The following observations were made regarding this procedure:
The performance test lacked qualitative and quantitative
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acceptance criteria; The test results suggest an increasing pressure
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differential across the 1A NS heat exchanger; While performing a quarterly test of the 1A containment
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spray heat exchanger on October 7,1985, the as-found RN l
flow rate of 800 gpm for that heat exchanger was l.
significantly below previous as-found test data.
uis
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condition was not evaluated by the licensee until requested by the NRC on March 24, 1986.
Additionally, l
during the test, a RN flow of 4600 gpm for the 1A containment spray heat exchanger was achievea rather than the 5000 gpm as specified in the procedure.
The inability to perform the test at 5000 gpm was not formally evaluated by the licensee until requested by the NRC on October 15, 1985.
Procedure TT/1/A/9100/105, RN Train IA Flow Verification requires that valve IRN73A, lA train RN Diesel Generator heat exchanger outlet isolation valve, be returned to its normal position at the completion of that test. On January 28, 1986, the NRC discovered that the proccdure was not followed in that valve IRN73A had not been returned to its normal position at the completion of that test earlier in the day.
Licensee emergency operating procedures for safety injection (EP/1/A/5000/01, EP/2/A/5000/01) and for transfer to cold leg recirculation (EP/1/A/5000/02 section 3, EP/2/A/5000/02 section 3) did not provide specific operator actions to assure proper nuclear service water flow through the diesel generator cooling water heat exchanger and containment spray heat exchanger during accident conditions in that required flow rates were not specifie _
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f
These are examples of a violation of 10 CFR 50 Appendix B'
Criterion V, which states that activities affecting quality shall be' prescribed by documented instructions, procedures, or drawings of a type appropric+.e to the circumstances and shall be accomplished in accordar.ce with these instructions, procedures, or drawings.
Instructions, procedures, or drawings shall
_ include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.
Resolution:
As stated in the resolution to the previous violation, the licensee has implemented a heat exchanger performance monitoring program that includes a quarterly test to flow balance the RN system. This procedure also contains provisions for flow balancing the RN system whenever it is found necessary to change the throttle position of a valve in order to establish adequate flow to any given system.
The procedure also contains design flow rates, target flowrates and as-found/as-left flowrate measurements. This procedure as well as the whole performance monitoring program adequately addresses two of the concerns noted above.
Specifically, the licensee now regularly performs flow balancing on the RN system and has provisions for controlling valve positions established during that testing. Tests and procedures associated with this monitoring program now contain adequate quantitative and qualitative acceptance criteria with which they can assure that the system will perform its intended function under design basis accident conditions.
The inspector reviewed emergency operating procedures for safety injection (EP/1/A/5000/01, EP/2/A/5000/01) and for
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transfer to cold leg recirculation (EP/1/A/5000/02 section 3, EP/2/A/5000/02 section 3).
These procedures now address the
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concern that specific operator action be performed to assure j
that there is proper RN flow through the diesel generator J
cooling water heat exchanger and, in the cold leg recirculation procedure, the containment spray heat exchanger also.
Based on this information, the item is closed.
k.
(Closed) VID 369/85-38-03 & 370/85-39-03: Failure to Adequately Establish and Maintain the Operability of the Stations RN System and the Performance of an Inadequate 10 CFR 50.59 Evaluation.
1.
Background:
Technical Specification (TS) 3.7.4 requires that two independent RN loops be operable for modes 1,2,3, and 4.
With only one loop operable they must restore both loops to an
operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
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On October.4, 1985,:following. inservice testing, the 1A RN pump performance was found to be degraded. The pump curve generated-
' from the test data deviated from the previously established
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baseline curve.
Delivered. flow was estimated to be approximately 85 percent of that required. TS 3.7.4 requires two'1 oops cf RN to be operable.
' '
The licensee performed a 10 CFR 50.59 analysis to justify cross-connecting the 1A.and 2A RN trains'in an attempt to boost-1A RN flow. After reviewing the 50.59 analysis-and extensive interaction with the licensee, the.NRC Region _II, on October 10, 1985, informed the licensee that the NRC considered lthe licensee was not meeting the requirement of TS 3.7.4 which requires. -two operable RN loops since the-1A train, was -
inoperable due to a degraded pump' and that the cross connected configuration could not be justified by a 50.59 analysis since it represented' the possibility of an unreviewed safety question
- and, in effect, changed the Technical Specification.
10 CFR 50.59 requires in part that - the holder of a license authorizing ' operation of a production or utilization facility
- may' make changes in the facility as described in the safety-analysis report without prior Commission approval, unless the proposed change involves a change -in the TS's incorporated in the license or an unreviewed safety question.
'
'Recclution:
This item was resolved via the enforcement actions associated with these items and the final disposition was stated in a letter from James M. Taylor, Deputy Executive Director. for Regional Operations to Hal B. Tm9.er, Vice President, Nuclear Production Department, Duke Power Company, dated July 23. 1987.
The response states in part that while the licensee asserts o
that an unreviewed safety question did not exist, this violation focused on the fact that the 10 CFR 50.59 evaluation was in error in that.the cross-connection would have placed the RN system in a configuration which would involve a change to TS 3.7.4.
The attempted cross-connection of the 1A and 2A RN
trains should have received prior NRC review and approval. TS 3.0.5 and 3.0.5a support the NRC position that the RN system was not a designated shared system in that the ACTION requirements are not indicated to apply to Units 1 and 2 as is the case for. shared systems.
Therefore TS 3.7.4 applies to each unit individually.
,
Based on this information, the item is closed.
l 1.
(Closed) VIO 369/85-38-04 & 370/85-39-04:
Failure to perform a 10 CFR 50.59 evaluation on degraded equipment.
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. Background:
On December '17, 1985, testing indicated that FSAR flow rate values could not be attained for the containment spray heat exchange'r. (4 percent. degraded), the control room chiller heat exchanger (10 percent degraded), the charging pump oil cooler (46 percent. degraded), the spent fuel pool pump room air handling. unit (56 percent degraded).
Although the data from this test indicated multicomponent degradation, the licensee performed an informal evaluation to support continued operation.
The results of. this evaluation were not documented. Not until requested by the NRC in January 1986, did the ' licensee perform a detailed engineering evaluation as required by 10 CFR 50.59.
Failure to ' perform this required evaluation was considered a violation of 10 CFR 50.59.
Resolution:
This issue required no licensee action. The NRC's evaluation of the licensee denial of this violation stated in part that any tests that cast doubt upon the operability of any component or system should be promptly evaluated.
An operability determination should be made in a time frame consistent with the safety importance of the system, as measured by the requirements of the Technical Specification Limiting Condition for Operation. A system should be declared inoperable pending completion of evaluation when there is schstantial evidence that it will not perform as assumed in the plant design basis.
Based on this information, the item is closed.
m.
(Closed) VIO 369/85-38-05 & 370/85-39-05:
Failure to identify and correct conditions adverse to quality as required by 10 CFR 50 Appendix B Criterion XVI.
Background:
The examples detailed in the items described in IE report 50-369/E3-38, 50-370/85-39 and listed in the violations listed above, represented a violation of 10 CFR 50 Appendix B Criterion XVI.
Resolution:
This violation was not included in the escalated enforcement action.
The resolution of the above noted violations are sufficient to close this item.
,
Based on this information, the item is closed.
I n.
(Closed) UNR 369/85-38-06 & 370/85-39-06: NRC follow-up of licensee
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response of April 25, 1986.
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' Background:
..
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meeting.. held on March 14, 1986,.'NRC-.
As : a ' result ofl a representatives. contacted the'l licensee's staff on March 24, 1986, to request-additional;information. DPC staff agreed to c formally - submit a;. response by April-25, 1986, regarding the
- following seven requested items:
Provide the as-found and as-left RN flow' balance te'st
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results for all RN trains; Provide the as-found and as-left Heat Transfer (UA) test'
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results for all containment spray heat exchangers; Provide a' RN operability determination for early October
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1985 L when RN flow was recorded as 800 gpm. to the 1A containment spray heat exchangers; Provide a safety evaluation of the January 28,- 1986 RN
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header pressure transient; Provide a RN operability determination based. on the 1A
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containment spray heat exchanger throttle valve setting which existed just prior to the first heat transfer test
~
and based on expected flow under accident conditions prior to heat exchanger' cleaning cycles; Provide the final parameters for use in the LOTIC program
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and their engineering basis; Provide DPC plars to prevent a recurrence of these events.
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Resolution:
The Licensee responded to all of these items, and while they remained firm in their denial of several of the violations, their response satisfied the request made of them. The portion of the response that is germane to the follow-up inspection of this issue concerned licensee plans to prevent recurrence of degraded RN system performance.
In their response, they attached their planned RN Syste'n Maintenance / Monitoring Program and their RN System Modification Plan.
The plans presented in
.
the response adequately address the concerns regarding the recurrence.
The inspector performed a review of the licensee's RN System Maintenance / Monitoring Program by reviewing procedures, l
i frequencies, results, and the overall condition of the ' heat l
exchangers. The inspector reviewed the following procedures:
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PT/1/A/4403/07, RN Train IA Flow Balance, changes 0 to 0;
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PT/1/A/4401/05A,. Component Cooling Train 1A Heat Exchanger Performance, changes 0 to.2; PT/1/A/4208/048, Train IB Containment Spray Heat Exchanger
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Performance Test, changes 0 to 11; PT/1/A/4208/03A, Train IA Containment Spray Heat Exchanger
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Performance. Test, changes 0.to 9; PT/1/A/4202/04, Spent Fuel Pool Pump 1B Air Handling Unit
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Performance Test, changes 0 to 0;
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PT/0/A/4457/03, VC/YC condenser A delta P Performance Test, changes 0 to-0; OP/1/A/6400/06, Nuclear Service Water System, changes 0 to
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60.
In addition to these procedures the inspector verified, but did not review, the other procedures in the program and their frequencies. All of the procedures being used for the program followed the licensee's April 25, 1986 response with the-following exceptions:
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The KC heat exchanger heat balance test was not a practical procedure as these heat exchangers are oversized to handle accident conditions and the licensee had no practical method of establishing a realistic heat load.
The fouling concern is addressed by the KC heat exchanger delta P test which is performed quarterly;
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The KD cooling water heat exchanger heat balance test was not being performed due to testing problems that rendered inconsistent reports.
The licensee has investigated the problem and plans to install pressure taps on the heat exchanger to facilitate the testing.
In the meantime the KD cooling water heat exchanger is subject to periodic cleaning.
The inspector found the procedures to be
adequate and complete in their instructions to ascertain J
the operability of their respective heat exchangers.
{
l Completed data packages from the following procedures were i
reviewed
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PT/1/A/4403/07; l
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PT/1/A/4208/03A;
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PT/1/A/4208/04B; PT/1/A/4401/05A.
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TheLinspector reviewed the licensee's data tabulation and.found-it to: be consistent with completed data sheets.
The. test results recorded the '.ast dates, test flows, ' uncorrected delta
.P.
corrected delta P at / design flow, and comments such as cleaning or flur.ing ~ performed before a retest.
The data sheets also ' nc edl the component,: component number, procedure, al design flow, and acceptance criteria.
The inspector l considered this evidence ' that the ' program.was well established and was accomplishing _its, intent.
In addition the inspector reviewed RN system trend plots that were being generated to aid.in the evaluation of heat exchanger performance.
These plots contained the test - data - results graphed with' the acceptance criteria.
The inspector. considers this a useful-' aid, but had the following comments:
The horizontal ' axis time scales contained several errors
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and in most'in' stances, were not linear; The plot for NS pump.1A area air handling unit delta P
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results had acceptance criteria that skewed upward for no apparent reason.
Overall, the inspector considers the actions taken by the licensee: both in responts to the escalated enforcement, and in c'
establishing a heat exchanger monitoring program to-be
,
'
satisfactory in-addressing this issue and closes all of the items associated with IE Reports 50-369/85-38 and 50-370/85-39.
Based on this information, the item is closed.
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o.
(Closed) VIO 369/85-45-01:
Inadequate post trip review relative to the reactor trip and safety injection on Unit 1 of November 2, 1985.
Background:
McGuire Nuclear Station Directive 3.1.10 defines the action to be taken in investigating reacter trips 1) to ensure full understanding of' the cause of the trip; the plant transient behavior before and after the trip; the trip's impact on nuclear safety, power production and performance; and 2) to identify necessary corrective action.
In addition, the directive prescribes the criteria that must be satisfied in order to restart the unit. Among.these is the requirement that
a review of the performance of safety systems be performed in order to identify other than expected performance.
Abnormal behavior requires in depth evaluation and resolution prior to restart.
If performance in all areas was as expected, the unit may be restarted.
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In the. post trip review conducted.for the, reactor trip of November. 2, 1985, discussed' in IE report 50-369/85-40, 50-370/85-41, it was noted in the list of, performance anomalies that one group of.. heaters.in pressurizer heater bank A was out
,
for 1.5 minutes during the transient. This was not evaluated
'
prior to.. restarting the unit and.the reason for the heater.
~
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failure was not determined.
.While DPC denied the violation, they stated that.the post. trip
'
review procedure, PT/0/A/4700/45, had been changed to instruct the post < trip review personnel to specifically check the
,
pressurizer heater alarm points following each transient and/or reactor trip.
.-
Resolution:
'The,. inspectors reviewed PT/0/A/4700/45 and verified that the above : stated changes were made.
In addition, the inspectors reviewed two post trip reports for occurrences on March. 25, 1986 on Unit I and August 12, 1986 on Unit 2.
The Aust 12,.1986,-incident was due to personnel working in the battery room accidentally causing the supply breaker to the main DC bud, EVDD, to 'open.
The CF containment isolation
~
valves and MSiV's began failing closed.
Both main feedwater pumps tripped on high discharge pressure..The main turbine tripped on the loss of both feedwater pumps.
The re' actor tripped on a turbine t.ip above P-8.
The March 25,' 1986, in',ident was attributed to a feedwater isolation valve to steam generator "B" closing suddenly. The unit tripped from 100 percent Full Power on "lo-lo" level on steam generator "B".
While reviewing the post trip review report for this occurrence, the inspector noted inconsistencies
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in the documentation of the initial start signal of the motor -
driven CA pump.
Specifically, enclosure 13.1 of the post trip review erroneously described the start signal of the CA pump as automatic on lo-lo steam generator water level and also as manual.
Subsequent investigations by the licensee, as documented on enclosure 13.3 of the post trip review report, determined that the pump had, in fact, been manually started by an operator from Unit 2, the unaffected unit, under direction given by the Shift Supervisor.
Because both of the Unit 1 operators were occupied with aligning the feedwater flow, they were not aware of the Unit 2 operator action, and assumed that the start signal was automatic. The Unit 1 operator documented
>
the automatic signal on the post trip review operator statement form.
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Based on this information, the item is closed.
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y o-The inspectors are concerned that an apparent lack of communication L
and awareness existed among the operators in regards'to starting the; CA : pump. The~ 1icensee should consider evaluating training and the, i
- incident itself to identify.whether or not training addresses this.
L
. issue; of communication when operators from an unaffected unit are directed. to assi st..i n the control. of the unit experiencing,a
. transient.-
5.
Licensee Action' on Previous-Inspector Followup Items.
a.
(Closed) IFI 369/81-39-02: Inspector Concerns Pertaining to Overtime Restrictions
'
N Background:
.
.
.o f IFI 369/81-39-02 was opened to track the. implementation _
NUREG 0737_ TMI Action Plan Items concerning overtime restrictions for licensed operators.
Commitments by the licensee' to satisfy certain overtime restrict _ ion requirements of NUREG 0737 were subsequently superceded by 'the' approval.of Unit 1 Technicei Specification Amendment 48 in. November 1985.
This amendment increased the overtime limits in the Technical Specifications to accommodate a change to 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts.*
Section 6.2.2.f-of Amendment 48 to ' the facility - Technicai
'
Specifications. requires that administrative procedures shall be developed and implemented to limit the working hours of unit staff who perform safety related functions, and that adequate shift coverage shall be maintained without routine heavy use of overtime.
The objective shal.1 be to nave operating personnel work a, normal 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> day with alternating 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> and 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> work weeks while the unit is operating.
When substantial overtime is worked on a tempen ry basis due to unusual circumstances, then an individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight, or be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, nor more than 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period, all excluding shift turnover time. Any deviations from these limits shall be authorized by the Station Manager or his deputy, or higher levels of management.
Individual overtime shall be reviewed monthly by the Station Manager or his designee to assure that excessive hours have not been assigned.
Resolution:
Station Directive 2.0.10, Revision 2, dated May 29, 1987 and entitled Overtime Authorization for Personnel Performing Safety Related Functions, implements Technical Specification Section 6.2.2 in part by providing administrative guidance to limit the working hours of hourly personnel in the tiechanical Maintenance, Instrument and Electrical, Health Physics, Chemistry, and Performance groups. The administrative guidance for the. Operations Group is covered in Operations Management
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Procedure (0MP) 1-7, Revision 3, ' dated February 9,[1986iand' '
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, entitled Shift Manning and Overtime Requirements.
ll The. inspect'or; reviewe'
Station. Directive 2.0.10 and OMP 1-7.
d
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Both. procedures stress.that2 overtime' should' Lnot be worked routinely by persons performing safety related functions,L and-
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. reflect' the overtime -, restrictions of the ~ Technical.
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. Specifications, with-the following. exceptions identified by the inspector:
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1)
Station -Directive 2.0.10 and OMP 1-7 require : that the Station Manager or his s designee review authorizede work hour e'xtensions in excess. of -the Technica1'. Specification -
guideline limits,; but do ' not require that all' individual
<
overtime be. reviewed to assure that routine heavy use of '
'
overtime. ' has not. been assigned, as; per -Technical
,
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Specification 6.2.2.f.
2)
Technical - Specification 6.2.2.f requires that deviations.
from the ' overtime limits be approved by - the Station
.
Manager, his : Deputy,. or higher levels of management.
However, revision 2 of Station Directive 2.0.10 (Revision 3 of the Request for Work Hours Extension form ) allows
.
work hour extensions to be approveu by the' Shift Engineer on duty when neither the Station Manager or, his deputy' (a Station Superintendent) are on-site. These cases.are to be reviewed by ' the affected Group Superintendent when he returns 'on site.
The reason for - this provision is discussed later in this section of the report.
To assess the extent of overtime use at the facility, the-inspector discussed overtime policies and practices with
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operations and maintenance personnel, and reviewed randomly selected time records for operations, maintenance and I&C personnel which included a recent Unit 2 outage.
Operations personnel generally worked 36 to 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> weeks, in compliance with the Technical Specifications, with occasional overtime
' typically being up to 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> per week. The Operations Group demonstrated practices to minimize overtime and equalize the.
distribution of overtime hours, including adequate staffing, a program of overtime rotation with identified qualified backups, and adherence to an informal 120 hour0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> administrative overtime
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limit for each two week period.
Based on'this information, the item is closed.
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The inspector reviewed additional areas of the licensee's overtime l
control program.
As required by Technical Specifications, both Station Directive 2.0.10 and OMP 1-7 require overtime beyond the established
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,g guidelines-to be authorized in advance and documented on an attached Request for Work Hours Extension form. Overtime is to be authorized ~
in advance to establish the: need for the o.ertime and verify that
- the~. work hour --extension - will' not affect the. performance or
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attentiveness..of.- personnel.' performing. duties : related - to. plant safety.
The forms are to be - reviewed monthly to ensure that excessive hours have not been assigned.
The monthly management'
-reviews required by Station Directive 2;0.10 are performed and documented-per PT/0/A/4700/31, Monthly Review of Station Overtime.
The' monthly reviews required by 0MP 1-7 are performed and documented ~
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using PT/0/B/4700/30, Monthly Review of Operations Shift Overtime.
' The inspector reviewed the completed copies' of PT/0/A/4700/31 and
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PT/0/B/4700/30 on file for.1985 through 1987 and verified that all the' monthly reviews had been. performed. However,' numerous instances were-identified where work hour extensions for Maintenance Group.
personnel had not;been approved in advance, but had been dated after
- the. fact. Examples included but were not limited to overtime worked-during the months of September.and October 1986, March 1987, and May through' July 1987.
The inspector discussed this finding with the Screrintendent of Maintenance, who stated that he: had identified this problem and addressed the issue at two Plant Superintendent Meetings in May 1987.
As a result,. Station Directive 2.0.2 was modified May 29, 1987, allow the Shift Engineer on duty.to approve work hour extensions when neither the plant manager nor a station
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superintendent is on site. The inspector noted that some work hour k
extensions during June and July still were not approved in advance after' this procedure revision was issued.
-The Maintenance Superintendent. stated that training on this procec'ure revision to emphasize the importance of prior approval-of overt.re had not been
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completed.
In reviewing the completed copies of PT/0/B/4700/30 for overtime for operations personnel, the inspector noted that the work hour extension' forms from OMP 1-7 did not document the dates on which the-overtime that exceeded the limits was worked.
This made it impossible to ascertain whether or not prior approval had been obtained without cross-checking other sources.
Additionally, the inspector reviewed the time records for maintenance personnel for two randomly selected weeks and picked six I
instances where an individual's overtime exceeded the technical specification guidelines, then compared these records to the work I
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hour extension requests filed with the completed PT/0/A/4700/31 L
overtime review for that month. As listed below, Request for Work l
Hour Extension forms were missing in five of the six cases, and in l
three instances the individual worked significantly in excess of the Technical Specification limit of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7 day period:
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Individual'A 73 hours8.449074e-4 days <br />0.0203 hours <br />1.207011e-4 weeks <br />2.77765e-5 months <br /> 6/16/87 Individual'B
- 87 hours 6/16/87-Individual C 74 hours8.564815e-4 days <br />0.0206 hours <br />1.223545e-4 weeks <br />2.8157e-5 months <br /> 6/16/87
' Individual D 87~ hours
.6/23/87 Individual B 87.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 6/23/87
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- This.. finding was-brought' to.the attention of the. Superintendent of Maintenance, who. stated-that all maintenance personnel.are
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considered to' be performing safety related.. work, and must, therefore, comply: with the. overtime limits of the Technical Specifications; and of-Station Directive 2.0.10.
Per procedure and practice,. the ' supervisors are tasked with assuring that work hour extension forms are' completed and submitted as required.
The. inspect' ors are concerned that lack 'of proceduralization for the monthly review of. individual overtime. by the Station Manager or his designee does not reflect the requirements of Technical Specification 6.2.2.f.
The inspector noted that-the lack'of a review of all individual overtime worked per Technical Specification 6.2.2.f could have contributed to this problem.
The failures to approve overtime in excess of the Technical Specification Limits in advance the failures to approve and r
document the excessive overtime for the individuals listed above, and the approval of excessive overtime by the Shift Engineer comprise a violation (VIO 369/87-26-01 & 370/87-26-01).
IFI 369/81-39-02 is administrative 1y closed and will be tracked via this violation.
b.
(Closed) IFI 369/81-39-04:
Resolution of Failure to Meet Loss of Offsite Power Test Acceptance Criterion Background:
Chapter 14 of the facility Final Safety Analysis Report (FSAR)
required that a loss of offsite power test be conducted at a power level above 10 percent of rated generator load to demonstrate the ability. of the turbine generator to sustain an isolation of the offsite power distribution system. and to subsequently act as the onsite power source, to evaluate the interaction between control systems, and to evaluate system rtsponses to the transient.
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During. the initial startup testing of Unit 1, an acceptance.
criterion which required the reactor and turbine not to trip was failed when the Loss of Offsite Power Test was first performed at 30 percent power on December 2, 1981. Shortly
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after the transient was initiated, a reactor trip occurred on
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reactor coolant pump bus underfrequency when the turbine / generator did not maintain house load.
No unexpected l
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' transient resulted from the. trip, and NRC inspectors witnessing the. test-identified no violations or deviations.
Resolution:
The. failure of.'the loss - of. offsite power test to meet the acceptance criterion.was identified in the Startup Report. -The repeat of the test was originally-scheduled to be for February 1982.
The NRC was notified.L in Supplement I to the Startup Report, ' dated May 1982, that due to an! extended ' outage, ~ the retest would be scheduled for June 1982.
The test' was.
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successfully completed on : June 24, 1982 and 'the results were -
- forwarded to. the NRC in Supplement 2. of the ' Startup Report, dated August, 17, 1982.
The. inspector reviewed the completion of.the Loss of Offsite
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Power ~ Test on June.12, 1984, as documented in TP/1/A/2650/12.
-All test' acceptance criteria were met.
Due to-the malfunction Jof a relay during the retest, the turbine. generator digital electro-hydraulic control system did not respond to the opening of the main switchyard breaker.. and kept the turbine in load control instead of transferring to speed c'ontrol.
Remaining in load control caused the overspeed protection circuit to close the governor and intercept valves.
This resulted. in a longer response time for the transient. All control; systems responded as required, and the reactor and turbine did~not trip.
The inspector verified - thet the malfunctioning relay was replaced.
The work was performed in accordance with Work Request 63748, completed July 9,1982.
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Based on this information, the item is closed.
c.
(Closed) IFI 369/81-39-05:
Safety Injections and Reactor Trip Caused by Problems with Instrument and Electronics (IAE) Procedures
NRC Inspection Reports 369/81-39 and 369/82-03 identified two safety injections and one reactor trip caused by errors in IAE procedures during a period of approximately a month. These incidents were collectively identified as IFI 369/81-39-05. The licensee committed to the NRC as a result of Inspection 82-03 to perform a general review and upgrade of the IAE procedures, as well as to revise the particular procedures involved in the incidents which are described below:
Example a:
Inadvertent Safety Injection on December 15, 1981.
Background:
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'While. performing a surveillance test on the Solid State Protection System (SSPS) on December 15, 1981, a safety injection signal was generated on low pressurizer pressure.
Personnel performing the test. missed a note in the procedure which stated, "If <P-11, press CA Auto-Start Defeat prior to tagging out pump to prevent Auto-Start when pump is energized."
Failure to heed this note caused the Train
"B".
auxiliary feedwater (CA) pump to start when the mode select switch was moved from the operate to the test position in the next step of the procedure. The decision was made to back up one step in the procedure by returning the mode select switch.to the operate position, so that the CA pump could be deenergized with the auto-start defeat in effect.
SSPS logic at McGuire is such that placing the mode select switch in the test position had cleared the P-11 blocks.
Since the plant was in mode 5 (cold shutdown) when the mode select switch was returned to the operate. position, a safety injection was immediately initiated due to the. low pressures in the primary and secondary systems.
Resolution:
The inspector interviewed the Instrument and Electronics (IAE)
technician involved in.the incident, and reviewed Incident Investigation Report Number 81-253. The interview and the investigation report both indicated the causes of the safety injection to be; a) Recent erroneous training by The vendor of the IAE technician involved, causing him to believe that l
positioning the mode select switch to test had no effect on the block logic, and b)
Procedural inadequacy in that the procedure did not include instructions for system restoration from all parts of the procedure. The report also attributed the incident to ineffective communications between the control operator and the IAE technician.
The inspector verified that later on the day of the incident, notes were added to procedure IP/0/A/3010/08, entitled Solid State Protection System (SSPS) Tests During Zero Percent Thermal Power (<1955 PSI), stating and emphasizing that if at
any time while performing the procedure, testing must be
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stopped and the system be returned to normal, the system
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restoration steps in section 10.10 must be performed in their L
entirety.
j Procedure IP/0/A/3010/08 was deleted in 1984 and replaced with two procedures which are train specific to reduce the potential for errors. These procedures (PT/0/A/4601/09A and 098) also provide instructions which are more specific and more detailed j
than in the original procedure, and have been reviewed for human factors considerations.
l The vendor and the Licensee's Training Center were notified of the training error, and modified their training accordingly, i
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JThe incident investigation'n report further stated that effective
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communication'would be stressed to station personnel.
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inspector concluded.that the specific' problems identified in
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~The1 this. example of'the IFI were adequately corrected by the licensee, Example b: ' Inadvertent Safety ~ Injection on December 24, 1981.
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' Background:
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with the reactornin mode 5, an-IAE
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On December 24,.1981.
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technician following.a step in the approved most recent change
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of IP/0/A/3000/09/K, Pressurizer Pressure Control Calibration, initiated a safety injection by placing all protection channels in. test at.the'same time. Placing more than one channel in test
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automatically. removed the P-11 block of the low pressure. safety injection signal when below 1900 psig, as in. mode 5.
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L, Resolution:.
30, 1982'-
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L Revision 3i to procedure IP/0/A/3000/09K, dated March
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-incorporated ' a series of changes to provide more' detailed-
. instructions and to clearly require that-only one channel test
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is performed at. a time.
Change number 8 to ' the' procedure,.
dated December 12,1984, is currently in place..This procedure has not yet been reviewed in the ongoing human factors program, but has been assigned high priority. The licensee' stated that
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the procedure has been performed on an 18 month basis since the incident without additional problems, u
. inspector concluded that the specific problems. identified in L
The
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this example of. the inspector followup item were adequately corrected.
Example c:
Reactor Trip on January 5,1982.
Background:
While at 90 percent power on January 5,1982, the unit tripped while an instrument procedure was being performed.
Resolution:
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l The inspector interviewed several licensee personnel either involved.in or familiar with the incident, who explained that the reactor trip occurred during logic testing of the Solid
State Protection System (SSPS) because the bypass breaker was removed prematurely.
h Recurrence of the incident was prevented by a procedural change to IP/0/A/3010/05 dated January 6,1982, requiring the bypass breater for the train under test to remain in place throughout
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the logic testing in the procedure so that returning the plant to normal would not trip the reactor. This does not prevent f.-
actuation of the Engineered Safeguards Features (ESF).
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Procedure IP/0/A/3010/05 was deleted in 1984 and replaced with
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Procedures PT/0/A/4601/08A and 08B, which are train specific-and more detailed.
The inspector reviewed PT/0/A/4601/08, Revision 4, Solid State Protection System (SSPS) Train
"A" Periodic Test, and did not identify any problems.
The problems identified in this example of the item were adequately corrected'by the licensee.
The inspector concluded that the corrections of specific procedural deficiencies as described above, the completion of two biennir.1 cycles of procedure reviews and upgrades since these inciderts'
occurred, the ongoing human factors reviews, and the general ga+n in plant ' operating experience since 1981 justify closure of the inspector follow-up item as described in the two inspection reports, d.
(Closed)
IFI 369/81-39-07:
Inspector Conce'rns Pertaining to Personnel leaving the Controlled Area without being Monitored for
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Radiation
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Background:
During a 1981 NRC inspection, the inspectors had noticed
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security guards stepping through the radiation monitors at the exit of the controlled area without pausing to be adequately monitored as required.
Resolution:
In 1982, the licensee installed radiation monitors designed such that a person cannot walk through without being monitored.
The counters are ultrasonically triggered, operate in a walk-through mode with a 0.4 second counting period, and count
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repeatedly during the entire time that a person.is passing over the ramps. A sign has been posted with instructions to pause on the footpad, but persons moving rapidly or running through the monitor will be still be monitored for several counting periods.
The licensee stated that they will be installing an additional upgrade of the exit monitor system, which will alarm if a person does not pause.
Based on this information, the item is closed.
e.
(Closed)
IFI 369/84-34-06 & 370/84-31-04:
Inspector Concerns Pertaining to the Calibration of Differential Pressure Transmitters.
Background:
This IFI documents an inspector concern pertaining to the calibration of differential pressure transmitters and whether the transmitters associated with the UHI are the only ones subject to the type of calibration difficulties as noted in VIO 84-34-03.
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Resolution:
The licensee identfiied 29 other installation types that may w,
have-the potential for installation errors with swapped lines.
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.These were examined by site. personnel who determined that j
either " indications" during' normal process variations or during
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various functional tests that. manipulated' the process would detect installations with crc'ssed impulse lines.. The only case that was identified that might not have been 1 detected by
" indicators" was the' containment pressure interlocks to the containment spray system, since these do not have " indicators" in the circuit.
These were physically examined and deter:nfned q
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to be correct. As noted in the resolution to VIO 369/34-34-02, e
- j the licensee has placed precaution statements in the Limits and Precaution section of differential prassure transmitter.
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maintenance procedures to avoid crossed connections.
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Based on this information, the item is closed.
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f.
(Closed) IFI 369-85-OL-02:
Inspector Concerns pertaining to Inaccuracies in Licensed Operator Lesson Plans.
l Background:
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i NRC examination report 369/0L-85-02 : dkuments three discrepancies in lesson plans used to develop a licensing examination.
The licensee committed to correct the affected lesson plans.
Resolution:
The first discrepancy involved the description of changes in differential boron reactivity worth over core life, and was contained in lesson plan OP-MC-SpS-RT-RCO, Reactivity Coefficients.
The ins 9ector reviewed the revised lesson plan
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dated August 23, 1985" and verified that the appropriate revisions had been made.
The second discrepancy involved the conditions for automatic
closure of the Standby Diesel Generator (SD/G) feeder breaker and was contained in the SD/G 1esson plan.
The inspector
reviewed the revised lesson plan and its associated handouts, j
and verified that the proper revisions had been made, j
The final discrepancy was contained in the safety injection system lesson plan and provided the incorrect logic for low steam pressure safety injection, The inspector reviewed lesson plans OP-MC-ECC-ISE, Engineered Safeguards, and
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OP-MC-SYS-SP-NI, $afety Injection System, ass well as the associated handouts.
The handouts and lesson plans reflected the correct logic.
Based on this information, the item is closed.
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(Closed) IFI 369/85-12-02 & 370/85-13-02:
Inspector Concerns Pertaining to the Participation of Backup Licensed Operators in the Lfeensed Operator Requalification Progran Backgromd:
.The'1985 Requalification Training Summary submitted to the NRC for approval on February 20, 1985 contained provisions for exempting ' backup licensed operators from participating in certain lectures and segment tests as management needs dictated.
The inspectors considered that these provisions were not specific enough to ensure adequate training of all backup licensed operators, and therefore should be revised.
Resolution:
The licensee has revised the requalification program for licensed operators. Standard 306.0, Periodic Training Licensed Operator Requalification, Revision 2, is an INPO accredited program and describes the requalification training necessary for maintaining an operator's license. This standard does not allow exemptions for backup licensed operators, but instead l
requires that' all licensed operators fully participate in the requalification program.
This standard became effective on i
l March 1, 1987.
l il The inspector also reviewed selected 1986 segment training for
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various individuals holding backup licenses.
This review
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indicated that the individuals holding backup licenses
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participated in segment training and completed the examinations
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consistent with requirements for all licensed operators.
Based en this information, the item is closed.
h.
(Closed) IFI 369/85-12-03 & 370/85-13-03:
Inspector Concerns Pertaining to Lecture Attendance Records.
Cackground:
The method of documenting requalification training lecture attendance lacked certification to assure that the attendance records were complete and accurate for e.ach individual.
Resolution:
The licensee revised the attendance forms for licensed and non-licensed requalification lectures to provide for
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instructor's initials certifying that the attendance data is
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complete and accurate.
The revised forms became effective in 1985 and have been incorporated in the McGuire Operations
l Tra t.11 ng Documentation /
Records Guideline, MC-0P-TG-09,
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I Revision 4.
The inspector reviewed selected attendance forms and verified the licensee's compliance with the new guidance.
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Based on this information, the item is closed.
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(Closed) IFI 369/85-12-04 & 370/85-13-04:
Inspector Concerns Pertaining to the Completion of the Operational Review Program.
Background:
The licensee uses the TSR-10 form, Training Content Summary, to document 'he content of operator requalification training
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programs.
These forms failed to provide documentation of completion of-the required. operational review program, making it po2sible for plant records to indicate sati sf actory completian of the requalification program prior to completing the required review of operational data.
Resolution:
The lict:nsee expanded the training summary provided on the TSR-10 form to include appropriate operational review program related information.
In addition, the operation review sign-off sheetr, which are used to document non-immediate review of related operational information, are attached to the TSR-10 form. Both the TSR-10 form and the sign-off sheet are part of the formal training records.
The inspector reviewed selected TSR-10 forms against training lecture outlines and associated sign-off sheets.
No discrepancies were noted.
Based on this information, the item is closed.
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(Closed) IFI 369/85-12-05 & 370/85-13-05:
Inspector Concerns Pertaining to the Licensee's Administrative Requirements for Lecture Attendance being Completed via the Operational Review program.
Background:
The licensee's operational review program together with the operational proficiency lectures appear to constitute the program for feedback of operational experience required by NUREG 0737.
With the administrative requirement for lecture attendance being a minimum of 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />, it is possible that personnel could fulfill attendance requirements without receiving all of the operational proficiency lectures. Actions should be taken to ensure that all licensed individuals fully participate in the program for feedback of operating experience.
Resolution:
Training guideline, MC-OP-TG-10, McGuire Operations Training Requalification Guidelines, was revised to specifically require that all operational proficiency lecture material be incorporated as part of the required review material for all licensed personnel.
Review of this material is documented on a i
sign-off sheet by trainees missing the lectures.
The sign-off
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sheet becomes part of the formal training records.
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participctian is required.
The inspector revieweo selected sign-off sheets and found no discrepancies.
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Based on this infortption, the item is closed.
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(Closed) IFI 369, 370/86-22-01: Inspector. Concerns Pertaining to tne
Licensee's Ability to Retrieve Traicing Records.
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Background:
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This IFI delineated the licentee's difficulty in retrieving
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training records, noting that the then current system was not wmcive
'.o either self-evaluation and analysis or quality
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assurance audit and rtriew.
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Resolution:
During the course of this close out inspection, numerous training records were requestad for review. In all cases, the licensee was able to provide the requested records with a I
d mir.imum of delay.
Based on this information, the item is closed.
1.
(Closed) IFI 369, 370/86-22-02: Inspector Concerns Pertaining /, the te
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Regrading of 7%uelif'
tion Examinations.
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Background:
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inspectar noted that two individuals who exhibited marginally
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satisfactory performance for two successive years achieved 5s.
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passing grades through re-evuuation and regrading of specific
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examination answers.
Although' a basis appeared to exist for each regrade, the inspector was concerned that there appeared to be no licensee Management review of the regrade process to ensure operator proficiency.
The licensee committed to establish provisions for requiring operations and training management < review for examination regrades that result in an individual changing from a fail to a pass status,
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f The inspectd also expressed concerns of instances where regrading la'cked documentation of the reason for the regrade and the identity of the person regrading, and that prior grades had been obliterated.
The licensee committed to establish y
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provisiens for the proper technique of regrading examinations
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witpin the Employee Training and Qualification System (ETQS).
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Resolution:
The McGuire Operations Training Requalification Guideline, MC-0P-TG-10, / delineates the management < uctidcation process utilized when an examination failure occur.s.
The inspector reviewed and verified that Revision 1 to tSis guideline, dated
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I June : 16,1 1987, specifically. requires that the Director of Operator - Training and the Superintendent _of Operations ' be notified of ' examination failures.
These notifications are-conducted prior to any regrading.
The : licensee also established instructions on grading examinations in 'the-McGuire Operations Training Exam.
. Administration'_ and Security Guideline, MC-0P-TG-05.
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inspector reviewed Revision _ 2 of the' guideline' and' verified
.that : instructions for regrading had been incorporated.
Specifically, the guideline. requires that the reason for regrading-as well; as' the responsible instructor's initials be documented on. the examination, and that the original grade remain clearly identifiable. These instructions are consistent with the licensee's commitment.
The, inspe; tor 'also reviewed selected regraded examinations to determine compliance with - the guidelinis.
No discrepancies were noted.'
Based'on this'information,the item is cloed.
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(Closed).IFI 369, 370/86-22-03: Inspector Concerns Pehtaining to the
. Training Provided to Licensed Operators on the Technical Specifications, Background:
This IFI delineates inspector concerns pertaining to the training provided to licensed operators on Technical Specification interrelationships and applicability.
Additionally, simulator examinations did not specifically evaluate ' operator-performance in Technical Specification
' identification.
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Resolution:
The inspector reviewed the Loss of Component Cooling Simulator
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I scenario lesson plan and the Requalification Program guide for simulator instructors and. found these documents to contain emphasis on the operators ability to locate Technical Specifications, identify Limited Conditions of Operation (LCO)
and corrective actions required if the' LCO is not met.
Additionally, the'
inspector.
reviewed NRC License
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Requalification Excercise Guide Worksheets and found those worksheets to contain evaluation points for the instructors to assess the operator's performance in Technical Specification
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Based on this information, this item is closed.
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(Closed) IFI 369,. 370/86-22-04: Inspector Concerns ' Pertaining to Lecture Attendance and Contact Hours for Requalification Training.
Background:
The inspector observed that the licensed operator requalification self-study time allotted was not adequately controlled.
The inspector considered that, under the licensee's policy, the potential existed for unacceptable substitutions of self-study for lecture attendance.
Resolution:
The licensee developed the McGuire Operations Training Student Policy Guideline, MC-0P-TG-01, to provide guidance on student behavior during operator training.
Revision 1 of-this guideline specifies that study periods must be used for study, and that operations instructors are responsible for ensuring that training is conducted in accordance with the guideline.
The instructors are also required to certify self-study attendance by completing and initialing the attendance form.
The attendance form becomes part of the formal training records, as required by the McGuire Operations Training Documentation / Records Guideline, Revision 4.
The INP0 accredited Licensed Operator Requalification Program requires 100 contact hours of instruction annually. Self-study periods that include an available instructor are considered as part of calculated contact hours.
Standard 306.0, Periodic Training Licensed Operator Requalification, Revision 2, limits self-study to 20 percent of the 100 contact hours required for planned lecture series.
Based on this information, the item is closed.
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SYS1EM ABBREVIATIONS
CA Auxiliary Feedwater System CF Feedwater System
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KC Component Cooling System
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KD Diesel Generator Engine Cooling Water System
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ND Residual Heat Removal System
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i NI Safety Injection System
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NS Containment Spray System NV Chemical and. Volume Control System RN Nuclear Service Water System VHI Upper Head Injection System VA Auxiliary Building Ventilation System VC/YC Control Area Ventilation and Chilled Water System VE Annulus Ventilation System VX.
Hydrogen Skimmer and Containment Air Return System
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