IR 05000315/1991017
| ML17329A188 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 09/16/1991 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17329A186 | List: |
| References | |
| 50-315-91-17, 50-316-91-17, NUDOCS 9109240374 | |
| Download: ML17329A188 (26) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos.
50-315/91017(DRP);
50-316/91017(DRP)
Docket Nos.
50-315; 50-316 License Nos.
Indiana Michigan Power Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, MI Inspection Conducted:
July, 23, 1991 through September 3,
1991 Inspectors:
J.
A. Isom s
D.
G. Passehl Z. Falevits Approved By:
B. PJ ge s
Chief Reactor P o ect Section 2A DATE Ins ection Summar In's ection from Jul 23 throu h Se tember
1991 Re ort Nos.
50-315/91017 DRP 50-316/91017 DRP Areas Ins ected:
Routine unannounced inspection by the resident inspectors of: plant operations; reactor trips; maintenance and surveillance; engineering and technical support; actions on previously identi'fied items; outages; emergency preparedness; and Bulletins, Notices and Generic Letters.
Results:
Of the eight areas inspected, no violations or deviations were identified in seven areas.
One violation was identified with two examples (removal of a breaker which resulted in cross-connecting safety and non-safety related motor control centers, Paragraph Sa; failure to update safety-related relay settings, Paragraph Sb) in the remaining one area.
The inspection noted strengths in the quality of support provided by the system engineering department for the troubleshooting and repair of the overspeed problem with the Unit 2 turbine-driven auxiliary feedwater pump and in the management of the Unit 2 outage.
The inspection also noted a weakness in that the troubleshooting and investigation into'he reactor trip breaker and the Unit 2 turbine-driven auxiliary feedwater pump anomalies failed to identify existing hardware problems.
9109240374 910917 PDR ADOCK 05000315
Plant 0 erations:
During this reporting period, Unit 1 operated at 99 percent power.
On July 23, 1991, Unit
CD emergency diesel generator was declared inoperable because of a modification which removed a breaker resulting in a safety and a
non-safety buss becoming cross-connected.
On July 24, after the breaker was replaced, Unit
CD was declared operable.
On August 19, 1991, an Unusual Event was declared when four shutdown rods became inserted four steps below their fully withdrawn position.
The withdrawal of the affected shutdown rods was satisfactorily completed and the licensee exited the Unusual Event later that day.
Unit 2 operated routinely at 98 percent power unti 1 a Unit trip on August 1, 1991.
The reactor trip was caused by a turbine trip.
The turbine trip was caused by the actuation of the main generator phase differential protective relays from a current transformer explosion, in the 765 kV switchyard.
Unit 2 was returned to service on August 24, 1991.
Maintenance and Surveillance:
The Inspector's review of the maintenance and surveillance activities during this reporting period found these activities were performed satisfactorily.
Review of past problem reports with the emergency diesel generators (EDGs)
found that there appeared to be an increase in the failures associated with the EDG air start system.
En ineerin and Technical Su ort:
On July 23, 1991 Unit
CD emergency diesel generator was declared inope'rable because of a modification which removed a breaker and resulted in cross-connecting safety and non-safety motor-control centers.
Additionally, the inspector noted that the licensee had inadvertently failed to update the solid state trip settings on four safety-related breaker DETAILS Persons Contacted
"A. A. Blind, Plant Manager J.
E. Rutkowski, Assistant Plant Manager-Technical Support L. S.
Gibson, Assistant Plant Manager-Projects
"K. R. Baker, Assistant Plant Manager-Production B. A. Svensson, Executive Staff Assistant
"J.
R.
Sampson, Operations Superintendent P.
F. Carteaux, Safety and Assessment Superintendent
"T. P.
Beilman, Maintenance Superintendent
"G. A. Weber, Technical Superintendent-Engineering
"T. K. Postlewait, Design Changes Superintendent
"L. J. Matthias, Administrative Superintendent J.
T. Wojci k, Technical Superintendent-Physical Sciences M. L. Horvath, guality Assurance Supervisor D.
C.
Loope, Radiation Protection Supervisor The inspector also contacted a number of other licensee and contract employees and informally =interviewed operations, maintenance, and technical personnel.
"Denotes some of the personnel attending the Management Interview on September 4,
1991.
Plant '0 erati ons 71707 71710 42700 Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant startup, steady power operation, and plant shutdown were observed.
The performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of Auxiliary Equipment Operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
The Plant Manager, Assistant Plant Manager-Production, and the Operations Superintendent were well-informed on the overall status of the plant.
Evaluation, corrective action, and response to off-normal conditions or events, if any, were examined.
This included compliance with any reporting requirements.
Observations of the control.room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
a.
Unit 1 operated at approximately 99 percent power throughout most of
'he period.
The following notable events associated with Unit
occurred during this inspection period:
(1)
Unit
CD Emergency. Diesel Generator (EDG) was declared INOPERABLE at 3:20 p.m.
(EDT) on July 23, 1991.
The licensee discovered that an electrical fault could propagate through a
non safety-related Motor Control Center (MCC 12-TSC-S), to an electrically "hardwired" safety-related Motor Control Center (MCC l-ABD-C), and trip EDG ventilation equipment powered.from MCC 1-ABD-C (see paragraph 5.a.).
The licensee replaced the breaker in the circuit between the two MCCs that had earlier been mistakenly removed.
The EDG was declared OPERABLE at 5:56 p.m.(EDT)
on July 24, 1991.
(2)
On Monday August 19, 1991 the licensee declared an Unusual Event because of a Technical Specification 3.0.3 entry when four shutdown rods (bank A group 2) were found inserted four steps below their fully withdrawn position.
Because Technical Specification 3. 1.3.4 allows only one shutdown rod to be below the fully withdrawn position, Technical Specification 3.0.3 was entered at 1:05 p.m.
(EDT). on August 19, 1991.,
and the Unusual Event was declared.
The condition was discovered when operators completed their monthly full length control rod operability test.
A flux map performed after the discovery confirmed the problem with the shutdown rods.
The cause was due to a
malfunction'of logic relays associated with shutdown bank, A group 2 rods.
The logic relays were replaced.
In order to meet Technical Specification requirements, the licensee'egan reducing reactor power and withdrew the affected shutdown rods one at a time.
The withdrawal of the shutdown rods was satisfactorily completed and the licensee exited the Unusual Event at 4:05 p.m.
(EDT) on August 19, 1991.
b.
Unit 2 was operating at approximately 98 percent power at the beginning of the inspection period.
Reactor power was limited to 98 percent power for thermal discharge limit considerations.
The reactor tripped on August 1, 1991 as a result of a turbine trip generated by the main generator phase differential protective relays (see paragraph 3.) when a current transformer (CT) failed on the Al 765 'kV circuit breaker in the, switchyard.
Following the generator trip, a fire was observed in the switchyard and the licensee made an Unusual Event declaration.
Firefighters responded to the scene and extinguished the fire.
No additional equipment was threatened by the fire.
The licensee originally intended to repair the breaker while remaining in MODE 3 and then return to power, but entry into MODE 4 was necessitated to repair a leak on the Component Cooling Water (-CCW) return header piping from the reactor coolant pumps.
MODE change was further delayed to repair a leaking equalizing line at valve 2-IMO-324 (West Residual Heat Removal (RHR) Heat Exchanger Bypass Valve).
On August 9, 1991 the repair was completed and the West RHR train was made OPERABLE.
The A1 765 kV circuit breaker was also returned to service on August 9, 1991.
The licensee commenced unit startup and MODE 3 was entered on August 10, 1991.
The startup was delayed pending resolution of the Turbine Driven Auxiliary Feedwater Pump (TDAFP) -intermittent overspeed trip problem (see
paragraph 4.b.)
and a leaking Conoseal on the reactor, head observed during the full temperature and pressure walkdown on August 11, 1991.
The licensee determined that the conoseal repair would require disassembly of the seal and placing the reactor coolant system in a reduced inventory condition.
The unit entered MODE 5 on August 13, 1991.
Following the repair, the unit began a
satisfactory and uneventful, reactor startup sequence.
The main generator was paralleled to the grid on August 24, 1991.
C.
On August 26, 1991 the licensee reported to the NRC a condition whereby operation of a Centrifugal Charging Pump (CCP) with suction supplied by the residual heat removal pump (during certain post-LOCA recirculation conditions) could result. in a diversion of water away from the recirculation sump to the Chemical Volume and Control tank (CVCs) hold-up tanks which are located in the auxiliary building.
The condition was discovered on the Cook Plant training Simulator and arose because of steps in the Emergency Operating Procedures (EOPs) that direct the operator to open the charging pump miniflow valves in preparation for switchover of the CCP discharge from the ECCS lineup to the normal CCP discharge lineup.
The basis for the procedure steps appears to be the EOP Emergency Response Guidelines which suggest that miniflow should be reestablished before isolating the Boron Injection Tank (BIT).
The licensee implemented an immediate solution which was to revise the affected EOPs.
The details of the issue were given to NRC Region III and NRR who intend to follow up the technical details and assess the generic impact during the next inspection period.
No violations, deviations, unresolved or open items were identified.
3.
Reactor Tri s
93702 On August 1, 1991, the Unit 2 reactor tripped as a result of a turbine trip generated by the main generator phase differential protective relays.
The relays actuated as a result of a fault in the phase three current transformer (CT) of the main output breaker.
.The reactor trip was without complication, all systems responded as expected, and offsite electrical power remained available.
'Because of the fire in the switchyard, the licensee declared an Unusual Event in accordance with their emergency classification procedures.
The licensee chose to let their oil-filled CT burn itself out.
Both onsite and offsite firefighting teams, responded to the scene.
Following the trip, the Turbine Driven Auxiliary Feedwater Pump (TDAFP)
responded properly but reached its electronic overspeed setpoint when shutdown of the TDAFP was attempted (paragraph 4.b.).
Also, one Main Steam Isolation Valve drifted fully closed and wa's promptly reset.
This was not unexpected.
The CT was subsequently disassembled and inspected.
The licensee could not conclusively determine the cause of the CT failure, but suspected
some insulation deterioration began sometime before the failure.
Some factors that led to the suspicion were the March 12, 1991 Unit 2 reactor trip due to the complete loss of the 765 kV transmission system and the May 12, 1991 reactivity transient on Unit 1 that caused an undervoltage condition on reactor coolant pump bus No.
3 that tripped the Unit
reactor.
The licensee indicated scheduling of pI'edictive and preventive maintenance for oil samples and gas-in-oil analysis was the responsibility of an offsite licensee group and may not have been properly performed.
The licensee indicated that plant personnel will assume responsibility for scheduling the maintenance.
No violations, deviations, unresolved or open items were identified.
Maintenance/Surveillance 62703 61726 42700 Corrective and preventive maintenance activities in the plant were routinely inspected.
Mechanical, electrical, and instrument and control group maintenance
'activities were included as available.
The focus of the inspection was to assure the maintenance activities reviewed were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and,in conformance with Technical Specifications.
The following items were considered during this review: the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The inspector reviewed Technical Specifications required surveillance testing as described below and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were properly accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that. deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following maintenance activities were reviewed or inspected:
a.
The inspector reviewed the past maintenance activities associated with the June 10, 1991 Unit 1 shutdown to repair arcing in the exciter cable tray.
The maintenance personnel, who were standing on top of the main exciter rectifier cabinets to access fire protection equipment, observed arcing beneath the Unit 1 main generator exciter.
Control Room Operators noted, main generator reactive power spikes occurred concurrently with the arcing.
Following the discovery, the licensee began a controlled shutdown to MODE 2 to investigate the event.
The inspector's review indicated that because of poor administrative control of the last maintenance activity associated with the exciter, the AC exciter stator leads were not reconnected to their AC power source.
The cause of the arcing was determined to be missing bolts to the exciter stator leads that connect the AC bus to the rectifier.
The exciter stator leads were inspected and pitting was noted on the surface where the exciter leads connected to an expansion joint on the AC bus.
The connections were cleaned and refinished and properly bolted.
The phase 3 connection showed the worst pitting and could not be satisfactorily refinished.
Instead, the expansion joint was "turned" so that the undamaged areas at the joint and the AC bus made up the new connection.
The inspector noted that an independent review by corpor'ate engineers agreed with the repair methodology.
Megger testing 'was then performed on the exciter stator and AC bus as a precaution.
The results were acceptable.
The inspector's review of the licensee's records determined that the connection was last disassembled during the 1989 refueling outage for an inspection of the exciter.
Records from that outage revealed that the exciter was disconnected, but the details of which leads were lifted and re-landed were incomplete.
A Maintenance Engineer Supervisor, assigned the exciter inspection at the time, documented the disconnect in his personal log book, but not on the "Lifted Mire Form" attached to Job Order No.
760077 written to document the exciter inspection.
The licensee agreed with the inspector that control and documentation for various lifted wires related to this activity needed improvement.
The licensee was questioned whether this event had any relation to the May 12, 1991 Unit 1 trip when a main generator reactive capabi lity special test was being performed (see NRC Inspection Report 50-315/91011; 50-316/91011(DRP) ).
The licensee believed the two events were unrelated.
The Plant Yianager reemphasized in a memo to his staff the requirement prohibiting walking or standing on energized enclosures.
This requirement was initially promulgated because of a June 1990 event when a technician, who was walking on top of the energized control rod power cabinets to work on fire protection equipment, may have contributed to a Unit 2 reactor trip.
The inspector reviewed the licensee's investigation and troubleshooting of the Unit 2 Turbine Driven Auxiliary Feedwater Pump (TDAFP) overspeed trip on August 1, 1991.
Upon receipt of the low steam generator water level signalsimmediately following the reactor trip, both the Motor Driven Auxiliary Feedwater Pump (MDAFP)
and the TDAFP started and ran as designed.
During the process of shutting down the TDAFP after it was no longer required, the TDAFP tripped on electrical overspeed.
The licensee's subsequent investigation identified the problem to be within the governor on
~ A
the TDAFP and the governor was replaced.
The. inspector noted that this particular overspeed problem associated with the Unit 2 TDAFP governor was a recurring problem which was not identified during troubleshooting of previous TDAFP overspeed events.
During one event the TDAFP overspeed problem occurred twi.ce during surveillance testing.
The events are documented in NRC Inspection Reports 50-315/90027; 50-316/90027(DRP)
and 50-315/91004; 50-316/91004(DRP).
The inspector observed
"Turbine Driven Auxiliary Feedwater System Test (**2-OMP 4030.STP.017T, Rev. 9, December 14, 1990),"
on August 3,
1991.
The licensee performed the test as part of troubleshooting activities to determine whether drift of Hain Steam Isolation Yalves would have any impact on proper. TDAFP operation.
The inspector noted no observable effect on TDAFP operation and the pump ran satisfactorily.
The inspector reviewed the continued testing on'August ll, 1991, performed to verify overspeed trip setpoints and to evaluate the effect of low Auxiliary Feedwater (AFH) flow rates on TDAFP operation while at 1000 psig steam supply pressure.
The test was run with the unit in NODE 3 to replicate conditions sensed on the TDAFP immediately after the reactor trip.
The testing was performed using "Turbine Driven Auxiliary Feedwater Pump Hechanical and Electronic Overspeed Tests (**12-HMP 5021.056.010, Rev.l, July 13, 1990)".
After the overspeed trip device was installed, the TDAFP failed to respond to controller settings and the licensee suspected the controller was unable to regulate air pressure to the governor.
The TDAFP was then declared INOPERABLE and Job Order B26074 was written to investigate.
The licensee's quality of troubleshooting for root cause analysis was good.
The licensee removed the governor cover and instrumented the governor air line and observed that the bellows within the governor responded to changing air signals from the controller.
However, the bellows response was not transmitted through the governor to the control valve and the licensee concluded the problem was located within the governor.
Subsequently, the System Engineer recommended, and the Plant Nuclear Safety Review Committee approved, replacement of the governor.
A The testing and dedication of the replacement governor were performed satisfactorily.
The dedication plan called for three consecutive starts of the TDAFP with full speed attained in 25 seconds or less.
The first few TDAFP start attempts were unsuccessful in that the TDAFP reached its required speed in roughly 33 seconds.
The licensee discovered the reason was that they were timing the entire TDAFP start sequence from switch actuation to full turbine speed.
The intent of the dedication plan was to test only the governor performance, so the licensee re-evaluated the dedication plan requirements and timed only the ramp of the governor.
The pump was retested and the governor response was noted to be under 25 seconds on three consecutive start attempts (about 24 seconds).
The TDAFP
successfully met the acceptance criteria of the dedication.
The inspector reviewed the associated Technical Specification requirements and noted the pump performance met the sixty second time to auxiliary feedwater injection in the steam generators (about 33 seconds).
Three mechanical and three overspeed tests were performed and all trip setpoints were within specification.
After the overspeed trip testing,, Operations Department 'personnel performed the surveillance test for operability using STP.017T
=
(referenced earlier)
and all results were satisfactory.
The TDAFP was returned to OPERABiE status on August 13, 1991 within the required Technical Specification time:limit.
The inspector reviewed the issue concerning the Unit 2 reactor head instrument port conoseal leak that was discovered by the licensee during the full pressure and temperature inspection on about August 10, 1991 as the licensee was preparing to return the unit to service following the forced outage that began August 1, 1991.
The leak was satisfactorily repaired after the unit was taken to MODE 5 on August 13, 1991.
After inspection of the conoseal the licensee determined the Marman clamp body o'n the conoseal was damaged and had to be replaced.
However, it was discovered that the clamp was no longer manufactured and spare clamps were unavailable from" this or other utilities.
The licensee decided to use an alternate design clamp (Articu-clamp)
manufactured by Westinghouse. 'ith assistance from Westinghouse, the licensee disassembled the instrument port utilizing the slightly modified "Reactor Reassembly" refueling procedure,
- 2-OHP 4050.FHP.004, Rev.O, October 26, 1990.
The installation of the new clamp was documented, as a Minor Modification, "Minor Mod" 02-MM-232 and on Job Order No. B013249.
Upon cleaning of the flanged surfaces of the conoseal, pitting was found at the area where the lower gasket seals.
A seal ring was welded to the male and female flanges to ensure a leak free seal.
The seal weld was processed as Minor Mod 02-MN-233 and documented on Job Order B38118.
The inspector reviewed "Unit 1 CD Emergency Diesel Generator (EDG)
Incomplete Start" (Problem Report 91-0863)
on July 14, 1991 that documented an event when EDG 1CD failed upon receipt of a start signal during performance of the monthly
"CD Diesel Generator Operability Test (Train A)." 1-OHP 4030.STP.027CD, Rev.6, February 7,
1991.
Operators stationed in the EDG Room reported that the diesel reached rated speed of 514 rpm in 9.1 seconds and that EDG parameters appeared normal prior to the trip.
Troubleshooting by the maintenance department instrument and electrical ( ICE) personnel traced the problem to an Agastat pneumatic timing relay that timed out too early.
The starting circuitry, designed to trip the EDG if it does not reach 95 percent of rated speed before the relay times out.
The inspector's review of the surveillance procedure with licensee
personnel indicated that because the diesel was rolled for about
seconds prior to the fast start, to check for accumulated oil or water in the cylinders, the air pressure in the receiver was lower than it is normally.
Consequently, the lower air tank pressure increased the EDG start time long enough for 'the Agastat relay to time out.
The system engineer indicated that the procedure would be reviewed to determine whether it should be more specific with respect to the allowable cylinder blowdown times.
A second EDG start was performed after the air receiver used for the surveillance had enough time to recharge to the 240 psig level delivered by the EDG air compressor.
The second attempt resu'lted in an 8. 1 second start and was successful.
Operations Department personnel then successfully completed
"CO Diesel Generator Operability Test (Train A)," and the EDG was satisfactorily returned to service.
The EDG was INOPERABLE for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 25 minutes, well within the T/S allotted time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The inspector noted the EDG has been satisfactorily tested on an increased frequency basis (weekly) since the event.
The inspector reviewed the investigation into the failure of EDG 2CD, which failed to start during performance of routine surveillance testing on August 18, 1991.
Unlike the event described above, the EDG did not roll at all upon the fast start attempt.
tlaintenance Department IKE 'personnel were contacted to investigate and found the problem to be within the starting air system.
Specifica'lly, a
degraded diaphragm was found in pressure regulating valve PRV-1.
The licensee replaced this PRV and other PRVs in the pneumatic control circuitry as a preventive measure.
Because of the two recent fai lures with the EDGs, the inspector performed a -review of past problem reports to determine whether there were other EDG failures
'aused by failures in the starting air system or related to the pneumatic controls associated with the EDG for both units.
Specifically, the inspectors noted the following failures:
(I)
CD EDG was INOPERABLE on March 25-26, 1991 due to a degraded control air regulator (PRV-I).
(2)
I AB EDG was INOPERABLE on June 3, 1991 due to a failure of a seal in a pilot operated valve (POV-4).
(3)
I CD EDG was INOPERABLE on July 14, 1991 due to a failed Agastat relay in the pneumatic control circuitry as described in paragraph 4.d.
above.
(4)
CD EDG was INOPERABLE on August 19, 199I due to a fai'lure of a control air regulating valve (PRV-1) as described in paragraph 4.e.
above.
(5)
2 AB EDG,was INOPERABLE on September 3,
1991 due to a failure of a pilot operated valve (POV-4).
The licensee was made aware of the inspector's concern and has made parts availability for the pneumatic controls. for all EDGs a high priority issue.
Additionally, the licensee is evaluating testing of all EDG pneumatic components without starting the EDG.
Additional inspection of this issue will be documented in the next inspection report, 50-315/91022; 50-316/91022(DRP).
The inspector reviewed an event during licensee performance of Unit 2 startup su'rvei 1lance testing when Reactor Trip Breaker
"B" failed to stay closed on demand.
The event occurred on August 10, 1991 during performance of "SU(1) Instrumentation Checks Prior to Startup," **2-IHP 4030.STP.180, Rev.5, July 24, 1989.
The problem was that the breaker did not stay closed when the control switch was placed in the closed position.'The licensee noted the breaker would close but immediately reopen.
The Maintenance Department Instrument and Electrical Group (-ISE) thought the problem was internal to the breaker and removed the breaker from the cubicle per Job Order B010786 for inspection and testing.
The procedure used to inspect and test the breaker was "Maintenance Inspection and Repair Procedure for llestinghouse Type DB-50 Air Circuit Breakers Installed as Reactor Trip Breakers Or Reactor Trip Bypass Breakers,"
- 12 flHP 5021.082.023, Rev.2, June 25, 1987.
The 18E group could find nothing wrong with the breaker during the various electrical checks performed.
The breaker was cycled numerous times and worked satisfactorily.
The breaker was replaced in its cubicle and again cycled satisfactorily.
The licensee suspected the breaker was "fixed" sometime during performance of the maintenance procedure and the breaker.
was declared OPERABLE on August ll, 1991.
However, the problem appeared again on August 23, 1991 when
"SU(1.)
Instrumentation Checks Prior to Startup,"
w'as again being performed.
The test was required to be performed since the licensee delayed unit startup to repair a leaking conoseal. 'ob Order B010202 was written to check the control scheme of the breaker, an activity, that was not performed during troubleshooting of the previous problem.
During the troubleshooting the licensee discovered a loose terminal
. screw on the breaker shunt trip attachment that could have caused a
decrease in voltage to the shunt trip relay, which would have been sufficient to cause the relay to drop out and cause the breaker to open immediately after closing.
The terminal screw was tightened
. and the breaker functioned properly thereafter.
The breaker was returned to OPERABLE status late on August 23, 1991.
This event wi 11 be reviewed further during the next inspection period as the inspector had not completed his entire review prior to the close of this inspection period.
The licensee checked the "A" train reactor trip breaker and noted no problem.
The bypass breakers were not checked because the licensee indicated the breakers did not have the same relays.
The licensee
stated the Unit I Reactor Trip Breakers would be checked during the next available outage time.
No violations, deviations, unresolved or open items were identified.
5.
En ineerin and Technical Su ort The inspector monitored engineering and technical support activities at the site and, on occasion, as provided to the site from the corporate office.
The purpose of this monitoring was to assess the adequacy of these functions in contributing properly to other functions such as operations, maintenance, testing, training, fire protection and configuration management.
'a ~
On July 23, 1991, the licensee made a notification to the NRC pursuant to 10 CFR 50.72 and declared the Unit 1 CD emergency diesel generator (EDG) inoperable.
A corporate engineer had discovered that plant modification RFC-12-3008, performed in November 1990, had removed a
100 amp, 600 Vac molded case circuit breaker between a
safety related motor control center (MCC) l-ABD-C, and a
balance-of-plant (BOP)
MCC, 12-TSC-S.
The feed was then
"hard-wired."
The breaker would have prevented a postulated fault in the BOP MCC from causing the main feed breaker to the ESS flCC to trip, resulting in loss of both MCCs and the ventilation system for the 1CD EDG.
The ESS MCC provides power to 1CD EDG auxiliaries.
Region III dispatched an electrical specialist to review the circumstances associated with this event.
The inspector.reviewed selected portions of the modification package, evaluated electrical design drawings and procedures and examined the modification design review process from the time the design was incorporated onto the drawing to the time it was field implemented.
In addition, corporate and plant engineers involved in the modification were interviewed.
Based on the reviews and evaluation, the inspector determined that the removal of the breaker in the field resulted from an inadequate modification design review performed by the licensee's corporate engineering and management personnel and the lack of attention to detail exhibited by corporate and field personnel reviewing and approving the design documents to remove the breaker.
At least seven engineers, supervisors, and managers had reviewed and approved the design documents, but failed to identify an error made in the modification package whereby a
BOP MCC was erroneously denoted as an ESS MCC.
This error eventually resulted in the removal of the breaker.
k The licensee's engineers agreed that the design review process should have identified this error prior to field implementation of the modificatio The inspector was informed by the supervisor of the Plant Engineering Department, who was knowledgeable of the Impell Electrical Protection Coordination Study, that the engineers at Impell had classified 12-TSC-S HCC as a safety-related HCC because they could not determine from the information they had what the classification of the HCC was.
The engineers believed at the time that this classification of 12-TSC-S HCC was conservative.
However, because 12-TSC-S was classified as a safety-related HCC, the engineers encountered breaker coordination problems between the loads which were supplied by 12-TSC-S HCC, the breaker between 1-ABD-C HCC and 12-TSC-S and the breaker supplying power to 1-ABD-C HCC.
To resolve this breaker coordination problem, the breaker between 1-ABD-C and 12-TSC-S was removed.
Failure to perform adequate design reviews of modifications and to correctly translate the design basis into drawings arid instructions
.
for field installations is considered to be an example of a violation of 10 CFR 50, Appendix B, Criterion III (315/91017-01A; 316/91017-01A).
An Impell Electrical Protection Coordination Study dated August 1988, identified mis-coordination concerns between 600 Vac bus solid state trip (SST) source breakers and motor control center (NCC) molded case breakers downstream, feeding extension HCCs.
Request for Change RFC-12-3008 was initiated to correct the mis-coordination concerns by adjusting the SST settings to coordinate with the larger molded case breakers.
The affected breakers fed safety related and BOP breakers on both units (600 Vac bus llB, llD, and 21 C).
The licensee implemented RFC-12-3008 but, when the activity was re-examined per NRC request, the licensee discovered that the propo'sed SST trip settings on four safety related and
BOP breakers had been inadvertently omitted from the relay setting sheets in the RFC package which was transmitted to the field in 1990.
Consequently, as of July 29, 1991, the field breaker trip settings on these breakers had not been changed to resolve the mis-coordination concerns noted in the 1988 Impell study.
The licensee performed an operability evaluation and determined that the failure to update the 600 Vac relay setting sheets and the field breaker 's SST setting had not impacted an earlier engineering evaluation performed in 1988 which concluded that a fault could lead to a loss of both the main and extension HCC loads within the same specific train.
The inspector reviewed the circumstances associated with this issue and concluded that an inadequate review process was applied to the
"Relay Diagrams," which recorded relay setting changes.
This resulted in the failure to correctly update most of the relay setting sheets and thus, the failure to change field breaker settings.
C.
Failure to perform an adequate design review of the relay diagrams to assure that the appropriate relay setting values had been determined and properly reflected for field implementation is considered an example of a violation of 10 CFR 50, Appendix B, Criterion I I I (316/91017-01B; 316/91017-01B):
During the previous inspection (NRC Inspection Report 50-315/91014;50-316/91014)
the licensee discovered design documents could not be located that would demonstrate the capability of the Emergency Di'esel Generator (EDG) combustion air exhaust and room ventilation systems to withstand the effects of a tornado.
Following that discovery, NRR granted a 30 day exemption of the tornado design criterion to allow modification of the specific components mentioned.
The modifications to the outside structures were completed and the licensee met the tornado design
'riterion requirements on August 16, 1991.
An additional damper will be installed in the EDG room ventilation supply by December 31, 1991.
One violation was identified and no deviations, unresolved items, or open items were identified.
I 6. 'ctions on Previousl Identified Items (92701 92702)
a
~
(Closed)
Unresolved Item 50-315/91004-01:
Confirm that Unit
normal boration flowpath was OPERABLE when the emergency boration flowpath appeared to have been blocked.
Two events involving some degree of blockage of the Unit 1 emergency boration flowpath occurred on February 12 and March 1, 1991.
On those dates the normal boration flowpath was INOPERABLE for planned maintenance and failure of heat tracing to maintain temperature greater than 145 degrees F., respectively.
Having the normal and emergency boration flowpaths out of service simultaneously placed the unit in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification Limiting Condition for Operation (T/S LCO).
The licensee reviewed test records and control room logs to determine whether the T/S LCO was unintentionally or unknowingly entered between the above dates since the emergency boration flowpath was assumed to have been blocked prior to March
and sometime after February 12, 1991.
The result of the licensee's review was satisfactory.
The inspector reviewed the daily and weekly boric acid flowpath temperature, readings,"
for the time period in question, found in "Heat Tracing Inspection and Boron Injection Tank Heat Tracing Operability and Operation - Data Sheets 1 and 2, Rev. 8, August 28, 1991."
Additionally, a satisfactory survei llance test was performed on February 24, 1991 which met the acceptance criteria of establishing greater than
gpm injection of boric acid via the normal injection pathway per "Boration System Valve Position Verification and Testing - Data Sheet 1, Rev.
3, March 23, 1990."
Finally, control room logs for the period were reviewed and no problems were noted.
b.
(Closed)
"Improper Installation of Heat Shrinkable Tubing (TI 2500-017)."
The issue was discussed in NRC Inspection Report No. 50-315/86035; 50-316/86035 where it was noted the licensee had an on-going evaluation of the extent of the problem at D.
C.
Cook.
After that evaluation, the licensee decided some questions existed as to the qualification of creased splices in RFC-01-2827 (Nuclear Splice Transmitter Kits) that needed to be resolved.
They inspected all splices in the, RFC where creases were known to exist.
The inspection entailed 43 splices in Unit 1 and 58 splices in Unit 2, per Job Order Nos.
716935 and 019186.
A total of nine splices were found questionable and were replaced.
The inspector reviewed the splice kit installation instruction (Instrumentation Lead Splicing Procedure,
- 12THP 6030 IMP.047, rev.
3, February 6, 1989)
and noted that it contains appropriate vendor installation directions and techniques to alleviate potential problems.
To date there appear to be no known problems with installation of splice kits.
No violations, deviations, unresolved or open items were identified.
7.
~Outa es (37700 42700 60705 60710 61701 61715 86700)
The inspector observed licensee management of the Unit 2 outage activities following the reactor trip on August 1, 1991.
The licensee's ability to quickly mobilize a competent and efficient outage management team (ONT) was noted as a strength.
The OHT implemented adequate controls for conduct of the outage.
Both planned and emergent work items were managed well.
Coordination between various departments,was good.
h'orker safety frequently received management attention and was a
factor in taking the Unit to NODE 5 to repair the leaking conoseal discussed in paragraph 4.c.
No violations, deviations, unresolved or open items were identified.
8.
Emer ency Pre aredness (82201 82203)
The inspectors participated in the licensee's August 27, 1991, off-hours, unplanned Emergency Plan Exercise.
The details of the exercise and the inspection, team's findings will be documented in NRC Inspection Report 50-315/91019; 50-316/91019(DRSS)
.
No violations, deviations, unresolved or open items were identified.
9.
NRC Compliance Bulletins~ Notices and Generic Letters (92703)
The inspector reviewed the NRC communications listed below and verified that: the licensee has received the correspondence the correspondence was reviewed by appropriate management representatives; a written response was submitted if required; and, plant-specific actions were taken as described in the licensee's response.
The inspector reviewed the six items required by TI 2525/103,
"Loss of Decay Heat Removal (Generic Letter No. 88-17)
CFR 50.54(f)
Programmed Enhancements ( long Term) Review" and found that the licensee has completed all program enhancements with the exception of the installation of RHR pump motor current and an annunciator for detecting approaching RHR malfunction caused by air ingestion under 12-RFC-4058 for both Units and issuing an emergency procedure for loss of RHR during reduced inventory conditions.
Alth'ough the inspector's review of various procedures was performed primarily using procedures associated with Unit I, Unit 2 procedures which dealt with the reduced or half loop inventory conditions were noted as being currently in effect.
The emergency procedure is expected to be completed by November of 1991 and the RHR pump motor current meter and annunciator are expected to be installed during the n'ext refueling outage for both Units in 1992..
Two instrument carts are available in the control room during
,half-loop or reduced inventory conditions.
One cart has the wide range level measurement, one channel of-incore temperature and the Hest RHR Heat Exchanger information.
The other cart has the narrow range level measurement, one channel of incore temperature, total,,return loop flow and East RHR Heat Exchanger information along with the TV monitor for visual sight glass observation.
Temporary Instruction 2515/103 was issued on December 12, '1989 to define the inspection and reporting responsibilities with regard to determining whether required actions have been taken by the licensee to prevent and, if necessary, to respond to loss of decay heat removal (DHR) during reduced reactor coolant system (RCS) inventory operation.
The following items in the Generic Letter (GL) were
'erified as follows through discussion with the licensee, review of various procedures and the inspector's observation of the reduced inventory instruments in the control room:
(I)
Inspection Requirement 05.02, Instrumentation (GL item I):
(a)
Verify that the licensee has provided reliable indications in the control room (CR) that describe the state of the RCS and the operation of systems used to cool the RCS.
RCS Level:
Three new independent level instruments were installed.
The three level instruments, included:
NGG-IOO: sightglass NLI-112: wide range level instrument NLI-122: narrow range level instrument Some relevant, heights are:
Reactor vessel flange:
approximately 621 feet Top of the hot leg:
615 feet and 2.5 inches Half-loop:
614 feet and 0 inches Bottom of hot leg:
612 feet and 9.5 inches Sightglass, NGG-100, replaced the original tygon hose setup'hat has historically been used.
It wi 11 measure from the reactor vessel flange to the bottom of the hot leg.
The level of the sightg lass can be observed locally and in the control room through use of the camera in containment.
A wide range level instrument, NLI-112, is used to monitor the level from approximately the reactor vessel flange to the bottom of the hot leg.
This instrument is a differential pressure cell which wi 11 give level changes due to pressure swings.
The instrument accuracy is within plus or minus I inch.
A narrow range level instrument NLI-122 is used to monitor level from approximately mid-loop to the top of the hot leg; The instrument is a capacitance type level detector.
The instrument accuracy is plus or minus 3/10 inch.
There are two low level audible alarms.
One of the audible low level alarms is initiated by the wide range instrument 'and the other low level audible alarm is initiated by the narrow range instrument.
Both of these alarms are set to initiate at 613 feet
inches.
Half-loop height is at 614 feet and 0 inches.
There are no alarms used to warn the operators of inadvertent entry into either the reduced or mid-loop inventory.
The prevention of inadvertent entry into either reduced or mid-loop entry is provided by adherence to
"RCS Draining," procedure
- 01-OHP 4021.002.005, Rev.
14, Yiarch 15, 1991, which is used to drain the reactor coolant system (RCS) to reduced inventory or half loop conditions with fuel in the core.
~RC Two incore thermocouples, NTI-100 and NTI-101, were installed to measure core exit temperatures.
Other existing temperature and flow instruments for the RHR system are also monitored on the instrument cart recorders in the control room.
These instruments are:
1-2-ITI-310 I-2-ITI-320 I-2-ITR-335 I-2-IFI-31I I-2-IFI-321 I-2-IFI-335 East RHR Heat Exch. Outlet Temp.
West RHR Heat Exch. Outlet Temp.
Total RHR Sys.
Return Temperature East RHR Heat Exch'utlet Flow West RHR Heat Exch. Outlet Flow Total RHR System Return Flow
The two incore thermocouples are alarmed to initiate at 170 degrees Fahrenheit (F).
'Other alarms are:
East and West RHR HX Outlet Flow High or Low High: 2600 GPM Low:
2300 GPM RHR Return To RCS Flow High or Low East and West RHR HX Outlet Temperature high or Low RHR Return to RCS Temperature High or Low DHR System Monitoring High'600 GPM Low:
2300 GPM High:
150 degrees F
Low:
80 degrees F
High:
150 degrees F
Low:
80 degrees F
Discussions with the licensee and review of correspondence between the licensee and NRR indicated that the installation of the instruments for RHR motor current capabilities wi 11 deferred until the next outage in 1992 for both Units.
This is the only hardware-related modification which needs to be installed for completion of Generic Letter 88-17.
(b)
Verify that procedures and administrative controls reasonably assure the indications are operational when needed.
Operational procedure,
"RCS Draining," **01-OHP 4021.002.005, Rev.
14, March 15, 1991 require that the wide range level detector be in service before draining the RCS to the top of the hot leg and the narrow range level detector be in service before draining the RCS from the top of the hot leg to the half loop level.
Currently, calibration of both the narrow and wide range indications are performed using a generic calibration procedure.
The inspector was informed by the IKC supervisor that the licensee plans to write a procedure specifically for the calibration of the wide and narrow range detectors before the next half-loop evolution.
F (2)
Inspection Requirement 05.03, Procedures (GL item 2)
(a)
Verify that procedures and administrative controls have been implemented that cover the NSSS, the containment, and supporting systems.
The licensee had the following procedures through which it appeared that they adequately controlled the NSSS, the containment and the supporting systems:
"Criteria For Operating At A Reduced Reactor Coolant System Inventory," PMI-4070, Rev. 0, August 3, 1989
"RCS Draining," **01-0HP-4021.002.002.005,'ev.
14, March 15, 1991.
"Operation of the Residual Heat Removal System,"
1-OHP 4021.017.001, Rev. 3, December 13, 1990.
"Loss of Residual Heat Removal (Shutdown Cooldown),"
1-OHP 4023.'017, Rev. 3, May 3, 1990
"Recovery From Loss of RCS Level h'hen Partially Drained Or At Half Loop,"
12-OHP 4022.002.013 Rev. 3, May 3, 1990
"RCS Draining" procedure addressed containment closure requirements prior to entry into reduced inventory requirements and the various prerequisites for initiation of RCS draining or entry into reduced or mid-loop conditions.
Additionally the plant manager'
instruction, "Criteria For Operating At A Reduced Reactor Coolant System Inventory," required that evolutions which could result in inadvertently draining the RCS be deferred to a time when the core is off loaded or the RCS has been refilled above the reduced inventory level.
Further,
"RCS Draining" procedure addressed the, means to add water inventory to the RCS and to provide long-term cooling if normal RHR systems become inoperable during reduced inventory operation and what supporting equipment is required to be operable for RHR operation.
(b)
Verify that written instructions and/or training reasonably assure that emergency procedures or the equivalent apply to reduced inventory operation.
The various emergency procedures used during reduced inventory operation are included among those discussed above.
(c)
Verify that it is not necessary to identify the actual event or cause of the event to achieve effective mitigation when the entire package of emergency procedures is considered.
The licensee is currently in the process of validating the emergency operating procedure which deals with loss of RHR during reduced inventory conditions.
The review is expected to be complete by November of 1991.
(3)
Inspection Requirement 05.04, Equipment (GL item 3)
(a)
Verify that adequate reliable equipment is provided for normal core cooling, including support equipment.
Plant manager's instruction, "Criteria For Operating At A Reduced Reactor Coolant System Inventory," requires the fo 1 lowing:
both trains of residual heat removal are to be available during operation'at a reduced RCS inventory
=
during RHR operation, service water (CCW and ESW) and back-up electrical power (i; e.
remain available for both trains of RHR, unless the fuel is off loaded or RCS level is greater than the reduce inventory level.
(b)
Verify that at least two reliable means'f cooling the core are provided during reduced inventory operation that are in addition to the normal DHR systems.
Plant manager,',s instruction, "Criteria For Operating At A Reduced Reactor Coolant System Inventory," and
"RCS Draining" procedure require the following:
one CCP with flowpath through the BIT or normal charging path AND
'I one SI pump with flow path to two RCS hot legs OR two SI pumps with flow paths to RCS hot and cold legs OR RWST gravity feed via RHR Suction flow path or SI pump flowpath AND one SI pump with a flowpath to the RCS hot and cold legs (c)
Verify that reliable communications wi 11 exist between CR personnel and personnel outside the CR (such as radios),
or at locations of specific activities in containment and in the auxiliary building, under, accident conditions.
The operators have various means through which they can-communicate with personnel outside the control room.
Some of these include hand-held walkie-talkies, normal in-plant annuciation systems and telephones.
(4)
Inspection Requirement 05.05, Analysis (GL item 4)
Verify that analyses have been performed or referenced where such analyses are necessary to properly prepare procedures.
The licensee has performed ECP I-2-N2-07 for their mid-loop monitoring system.
(5)
Inspection Requirement 05.06, Technical Specifications (TS)
(GL item 5)
Verification of changes needed to the TSs was not required to be performed by the resident inspectors.
(6)
Inspection Requirement 05.07, RCS Perturbations (GL item 6)
(a)
Verify that the licensee has completely considered potential perturbations of the RCS and supporting systems by training, procedures, and controls that reasonably avoid perturbing activities when RCS inventory is low and decay heat is high.
By plant manager's instruction, "Criteria For Operating At A Reduced Reactor Coolant System Inventory," activities which may perturb the RCS inventory are prohibited until the core is off loaded or the RCS has been refilled above the reduced inventory level.
(b)
Verify that extra precautions are taken where such potentially perturbing. activities must be so conducted.
Such activities are not allowed by the plant manager'
instruction, "Criteria For Operating At A Reduced Reactor Coolant System Inventory."
b.
Based on the licensee's actions as detailed above, Generic Letter 87-012 is considered CLOSED.
Ho violations, deviations, unresolved or open items were identified.
10.
~Hang ement Interview The inspectors met with licensee representatives (denoted in Paragraph I)
on September 4,
1991 to discuss the scope and findings of the inspection.
In addition, the inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents/processes as proprietary.
21