IR 05000341/1993006
| ML20036A381 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 05/05/1993 |
| From: | Phillips M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20036A378 | List: |
| References | |
| 50-341-93-06, 50-341-93-6, NUDOCS 9305110151 | |
| Download: ML20036A381 (39) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION REGION 111
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Report No. 50-341/93006 (DRP)
Docket No. 50-341 License No. NPF-43
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Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name:
Fermi 2 Inspection At:
Fermi Site, Newport, Michigan Inspection Conducted: March 10, 1993, through May 3, 1993 Inspectors:
W. J. Kropp K. Riemer R. Twi
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Approved By:
M-h Chief
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f N e. actor Projects Section 2B D' ate /
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Inspection Summary Inspection from March 10. 1993. throuah May 3. 1993 (Report No. 50-341/93006(DRP))
Areas Inspected:
Routine, unannounced safety inspection by the resident inspectors of action on previous inspection findings; operational safety verification; onsite event followup; current material condition; housekeeping J
and plant cleanliness; radiological controls; security; LERs; maintenance activities; surveillance activities; system engineering; operability I
assessment; potential design changes; and report review.
Results: Within the fourteen areas inspected, one violation that pertained to
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inadequate testing to comply with Technical Specifications (paragraph 4.a) was identified. Two Unresolved Items were identified that pertained to inadequate post modification testing (paragraph 6.c) and the Potential Design Change "at risk" process (paragraph 6.c).
One Inspection Followup Item was identified that pertained to fuse coordination (paragraph 4.a).
The following is a summary of the licensee's performance during this
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inspection period:
9305110151 930505 PDR' ADOCK 05000341
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Plant Operations The licensee's performance in this area was good during this inspection period. The operator's response to a reactor trip was good.
Shift briefings and plan of the day meetings continue to be excellent with good command and control exhibited by the shift supervision. The inspectors were concerned with the Operation Department's lack of attention to detail.
Four instances were identified that included a component's local. control switch not properly tagged out of service, an equipment status not properly identified on the main control board, failure to recognize a malfunctioning level control valve, and a failurn to recognize inoperable instrumentation. Material condition of the plant was good with housekeeping being excellent.
Safety Assessment /0uality Verification The inspectors reviewed four Licensee Event Reports during the inspection period with no problems noted. The licensee's performance in this area was
good. However, the inspectors identified problems in the design change process concerning "at risk" construction and post modification testing. These problems had not been previously identified by the licensee's Quality Assurance Department.
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Maintenance and Surveillance The licensee's performance in this area was mixed. The maintenance on Emergency Diesel Generator 12 was performed in a well planned manner that contributed to minimize outage time. However, problems were identified with
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post modification testing for modifications installed under the auspices of maintenance.
Enaineerino and Technical Support
The licensee's performance in this area was adequate. The system engineer's involvement in an EDG outage contributed significantly to limiting outage time. However, there were problems identified in the operability assessment for a containment isolation valve. Also, problems were identified with the Potential Design Change "at risk" process and the failure to identify adequate post modification testing for a replacement of a HPCI suction pressure switch.
The reactor trip on April 20, 1993, was caused by an engineer inadequately monitoring the installation of a temporary modification by a contractor.
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I DETAILS l
1.
Persons Contacted Detroit Edison Company
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D. Bergmooser, Technical Engineering
J. Conen, Senior Engineer, Plant Safety
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- R. Eberhardt, Superintendent, Radiation Protection
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- P. Fessler, Director, Technical Manager
- D. Gipson, Senior Vice President, Nuclear Operations
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L. Goans, Nuclear Security
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- L. Goodman, Director, Nuclear. Quality Assurance E. Hare, Senior Compliance Engineer, Licensing
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R. Henson, Operations
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K. Howard, Mechanical and Civil Engineering, Supervisor J. Korte, Director, Nuclear Security i
A. Kowalczuk, Maintenance Superintendent R. Mathews, Maintenance
- R. McKeon, _ Plant Manager, Nuclear Production i
- W. Miller, Director, Nuclear Licensing
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- R. Newkirk, Supervisor, Licensing
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D. Ockerman, Nuclear Training
W. Orser, Senior Vice President, Nuclear Operations
- G. Pierce, Work Control
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- J. Plona, Superintendent, Operations
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- R. Stafford, Nuclear Assurance Manager
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- J. Tibai, Compliance, Licensing
- W. Tucker, Superintendent, Technical Engineering
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- J. Walker, Director, Plant Engineering i
Nuclear Reaulatory Commission
- J. Zwolinski, Assistant Director, Region III Reactors
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- W. Dean, Acting Director, Project Directorate III-I i
- T. Colburn, Project Manager, Project Directorate III-I (
- M. Phillips, Section Chief,-Projects Section 2B, Region III
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- W. Kropp, Fermi 2 Senior Resident Inspector l
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- Denotes those attending the exit interview conducted on May 3, 1993.
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- Denotes those attending the management meeting on April 28, 1993.
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The inspectors also had discussions with other licensee employees,_
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including members of the technical and engineering staffs, reactor and i
auxiliary operators, shift supervisors, and electrical, mechanical and
instrument maintenance personnel, and security personnel I
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2.
Action on Previous Inspection Findinas (92701)
(Closed) Inspection Followuo Item (341/92021-05 (DRP)): The standby auto start feature of the diesel fuel oil transfer pumps (DF0T) on low l
day tank level was not completely tested. The inspectors reviewed the
applicable station procedures and determined that the auto start feature
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of a DF0T on low day tank level was adequately tested. This matter is (
considered closed.
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Plant Operations j
Fermi 2 operated at power levels up to 98 percent until April. 7,1993, j
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when the unit was operated at reduced power levels in response to-a failure in an extraction steam line. The unit was shutdown April 10 to
repair the extraction steam line.
On April 20 during unit restart i
following the extraction steam line outage, the plant tripped at
approximately two percent power. The results of the inspectors' post
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reactor trip investigation are documented in paragraphs 3.b and 6.c of this report. The unit was returned to service on April 22, 1993, at
3:23 a.m. (EST), 'and has operated at power levels up to 98 percent.
a.
Operational Safety Verification (71707)
l The inspectors verified that the facility was being operated in conformance with the license and regulatory requirements and that l
the licensee's management control system was effective in ensuring
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safe operation of the plant.
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On a sampling basis,.the inspectors verified proper control room
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staffing and coordination of-plant. activities; verified operator
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adherence with procedures and technical specifications; monitored control room indications for abnormalities; verified that
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electrical power was available; and observed the frequency of
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plant and control room visits by station management. The i
inspectors reviewed applicable logs and conducted discussions with i
control room operators throughout the inspection period. The i
inspectors observed a number of control room shift turnovers. For i
the most part, the turnovers were conducted in a professional j
manner and included log reviews, panel walkdowns, discussions of.
H maintenance and surveillance activities in progress-or planned, and associated LC0 time restraints. During walkdowns of the plant, the inspectors identified the following concerns:
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On March 10, 1993, the local control switch for the Division l.
I switchgear room air conditioning-(AC) unit, T4100B39A, was I
noted in the "off" position.
There was no equipment tag on the switch. The switch has three positions: off, run, and auto. The other Division I switchgear room AC unit,
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T410040A, was in the "run" position. The inspectors l
i determined that there was no open work' request (WR) for T4100B039A. The investigation resulted in the licensee
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issuing WR 000Z931341 to determine the cause of T4100B039A
not running. The licensee also tagged the local control switch for T41005039A with an equipment tag.-
Even though the AC units for the Division I switchgear room were non-
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safety related and non-Technical Specification components,
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the inspectors were concerned with the lack of a WR and an equipment tag for equipment not in. service.
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On March 12, 1993, during a walkdown of the main control boards, the inspectors noted that annunciator SD117,
"Feedwater Heater 1S Level High/ Low," annunciator alarm on
the Defeat Matrix Panel was defeated.
The inspectors noted
that the level in the IS Feedwater Heaters was below the low level alarm. At the time, the unit was at 98 percent power.
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.The inspectors questioned the control room operators as to why there was a low level in the IS feedwater heater. The
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operators stated that the alarm had been defeated at the-l Defeat Matrix for several weeks but did not give a specific
reason for the low level.
Subsequent. investigation by the
licensee determined that the control air to the 1S Feedwater
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Heater Level Control Valve, N22F400C, was isolated. The isolation of control air failed the valve to the open
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position which caused the low level in the IS Feedwater
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Heater. Also, the licensee found the air supply to level control valves, N22F400A and B, isolated which failed these valves open. These valves maintained level in the IC and IN
Feedwater Heaters. However, due to the plant being at 98 percent power, there was sufficient drain flow to maintain
level in the IC and IN Feedwater Heater above the low level
al arm.
The licensee issued Deviation Event Report 93-0150 l
for this event.
e On March 19, 1993, during routine control room panel
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walkdowns, the inspector noticed that the Division I Accident Monitoring Instrumentation was improperly marked as
being in an LC0 status.
Division II Accident Monitoring was inoperable because of maintenance on the Division II Emergency Equipment Cooling Water (EECW). The Division II Accident Monitoring Instrumentation System was properly recorded as-being in an LCO status in the control room LCO log.
However, labeling on the control room panels indicated that Division I Accident Monitoring was in an LC0 status; there was no indication that the Division I Accident Monitoring Instrumentation was actually inoperable and in an LCO. When the inspector pointed out the discrepancy between the LC0 log and control room panels, the operators switched the panel labeling to correctly identify the status of the Division I and II Accident Monitoring Instrumentation.
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In addition to the above plant conditions identified by the inspectors, the licensee identified the following:
On April 30, 1993, at 11:45 pm (EST), the Shift Technical Advisor (STA) identified that the Division I Post Accident Monitoring (PAM) instrumentation for reactor pressure indicated downscale.
The licensee immediately entered the applicable Technical Specification (TS) Action statement for an inoperable post accident monitoring instrument. The licensee found that a blown fuse was the cause of the downscale reading. The fuse was replaced and the Division I PAM reactor pressure instrument was declared operable. The TS Action statement was then exited by the licensee.
Preliminary investigation by the licensee determined that a surveillance was performed on the Division I PAM in accordance with procedures 44.030.257 and 44.120.001.
The surveillance was completed at 2:20 p.m. (EST) on April 29, 1993. Review of historical data determined that the PAM reactor pressure instrument failed downscale at 2:08 p.m. on April 29, 1993.
Prior to the identification of the failed instrument by the STA on April 30, 1993. there was opportunity for operations personnel to have identified the failed instrument during shift turnovers.
The inspectors will review the licensee's corrective action as noted on Deviation Event Report (DER) 93-0243.
Even though the above examples did not adversely impact plant safety, the inspectors were concerned with the lack of attention to detail by operators during this inspection period.
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Onsite Event Follow-up (93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events l
onsite with licensee and/or other NRC officials.
In each case,
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the inspectors verified that required stification was correct and timely. The inspectors also verified that the licensee initiated prompt and appropriate actions.
The specific events were as follows:
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e On April 10, 1993, the licensee commenced a reactor shutdown
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to repair an extraction steam line inside the condenser.
The line supplies steam to the Number 4 feedwater Heaters and was the same line that failed in December,1993.
At 1147 a.m. (EST) on April 7,1993, the control room operators received an alarm that indicated the 4N/45 Feedwater Heater Extraction Steam Check Valve had closed.
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Level oscillations were observed on all feedwater heaters and power output decreased by approximately 30 MW (gross).
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Operators reduced power to approximately 95 percent to stabilize feedwater heater levels.
Preliminary analysis
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indicated that the extraction steam line from the Center low Pressure Turbine to the Number 4 Feedwater Heaters had partially failed.
The unit was operated at reduced power levels from April 7 to April 10. The licensee commenced a reactor shutdown at 1:44 p.m. (EST) on April 10, 1993. The unit was placed in
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Mode 3 (Hot Shutdown) at 1:02 p.m. on April 11, 1993.
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After the unit was placed in a cold shutdown condition, licensee personnel entered the condenser to troubleshoot and repair the failed extraction steam line. The new bellows, l
installed during the December 1992 outage, had l
catastrophically failed.
The licensee's engineering analysis indicated that the failure was due to high cycle
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Further analysis showed that the licensee's i
repairs in December caused the extraction steam line in the condenser to vibrate at a resonant frequency. The piping i
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bellows failed. The licensee redesigned the line using a l
hard pipe arrangement without the bellows. As part of the l
modification, the piping support at the condenser wall was
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modified and strengthened. The licensee also added instrumentation (strain gauges and accelerometers) to l
monitor the line during operation.
See paragraph 6.c for
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further details concerning this modification.
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Following completion of the maintenance outage to repair the
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extraction steam line, the licensee commenced a reactor startup on April 20, 1993.
During the plant heat-up, at
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approximately 2 to 3 percent power, the reactor tripped on high flux.
Pressure regulator failure caused the main turbine bypass valves to open.
Reactor vessel water level increased and then decreased when the bypass valves opened.
The decreased reactor water level increased the demand for
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feedwater. As a result of the colder feedwater being injected into the core, reactor power increased 10 the Intermediate Range Monitor (41RM) Upscale Trip Setpoint.
The pressure regulator failure was due to a steam leak i
blowing steam onto pressure transmitters. -The steam was leaking from a transducer installed to monitor the main l
steam manifold for startup testing. The apparent cause of i
l the leak was that the transducer was not compatible with the
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fitting on the instrument line. The event will be further I
reviewed by the inspectors during the LER review.
See
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paragraph 6.c for further details.
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On April 21, the licensee commenced a reactor startup f
following replacement of the pressure transmitters. The
unit was synchronized to the grid at 3:23 a.m. (EST) oa
April-22, 1993. During observation of startup activities on
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April 22, the inspector noticed that the Reactor.
Recirculation (RR) pump."B" speed was approximately 6'
percent higher than the RR pump "A" speed.
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discrepancy was pointed out to the control room staff,-
operators took steps to reduce the RR pump "B" speed and make it' consistent with the RR "A" speed. -The operators
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initiated a DER 93-0223 to document the discrepancy.
Preliminary investigation by the licensee determined that
this condition existed approximately 20 minutes prior to being identified by the inspector. The inspectors will track.the licensee's resolution during routine DER review.
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c.
Current Material Condition (71707).
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The inspectors performed general plant and selected system and I
component walkdowns to assess the general and specific material i
condition of the plant, to verify that work requests ~had been
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initiated-for identified equipment problems, and to evaluate housekeeping. Walkdowns included an assessment of' the buildings, components, and systems for proper identification. and -tagging, accessibility, fire and security door integrity,- scaffolding,,
radiological controls, and any unusual conditions.
Unusual
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i conditions included but were not limited to water,. oil, or other
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liquids on the floor or equipment; indications. of. leakage through
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ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting. Overall, the inspectors considered the material condition of the plant as good.
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Housekeepina and Plant Cleanliness.
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The inspectors monitored the status of housekeeping and plant
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cleanliness for fire protection and protection of safety-related.
equipment from intrusion of foreign matter.
Housekeeping was considered very good during this' inspection period.
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Radioloaical Controls (71707)
The inspectors verified that personnel were following health
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physics procedures for dosimetry, protective clothing, frisking, posting, etc., and randomly examined radiation protection instrumentation for.use, operability, and calibration.
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Security (71707)
Each week during routine activities.or tours, the inspectors monitored the licensee's security program to ensure that observed
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plan.
The inspectors noted that persons within the protected area displayed proper photo-identification badges, and those individuals requiring escorts were properly escorted.
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packages entering the protected area were searched by appropriate
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equipment or by hand.
No violations or deviations were identified.
4.
Safety Assessment /0uality Verification (40500 and 92700)
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Licensee Event Report (LER) Followuo (92700)
Through direct observations, discussions with licensee personnel, and i
review of. records, the following licensee event reports were reviewed to
determine that reportability requirements were fulfilled, that immediate l
corrective action was accomplished, and that corrective action to prevent recurrence had been or would be accomplished.in accordance with
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Technical Specifications (TS):
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(Closed) LER (341/93004):
Reactor trip due to turbine
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trip / reactor trip caused by high condenser pressure. The
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licensee determined the root cause was personnel error when
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an electrical maintenance individual placed test equipment i
across the wrong relay during a preventive maintenance
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j activity. The inspectors reviewed the licensee's analysis
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.of the event and corrective actions and agreed with the
licensee's actions and conclusions.
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o Closed) LER (341/93005):
Primary Containment Isolation Valve, T49-F468, closed when a fuse blew during the
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replacement of a burned-out lamp.
The inspectors reviewed
the licensee's analysis of the event and corrective actions with no concerns identified. During the analysis of the i
event, the licensee identified a potential fuse coordination problem with twenty circuits. The licensee will further evaluate the need to replace the fuses.
Pending further review by the licensee and NRC, the fuse coordination of the twenty circuits is considered an Inspection Followup Item (341/93006-01(DRP)).
e (Closed) LER (341/93006): Test procedures used to perform channel functional tests and channel calibration of Reactor Protection System and Electrical Protection Assemblies (EPS)
were incorrect.
Due to concerns raised by the inspectors, the system engineer identified that the procedures failed to trip the EPA breaker as. required by Technical Specification (TS) 1.6 and 4.8.4.4.
The procedures, as written, verified the undervoltage, overvoltage, and underfrequency EPA.
channel trip functions by using installed test equipment
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rather than an actual circuit breaker trip. This condition
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had existed since March 1991 when Engineering Design Package l'
(EDP) 9922 installed new test components. The inspectors have reviewed the licensee's corrective action described in the LER with no problems being noted. The licensee
immediately and successfully tested the EPA breakers.
Since
the discovery of the improper testing of the EPA breakers
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was a result of an inspector's concerns, the failure to test i
EPA breakers in accordance with TS is considered a violation l
(341/93006-02(DRP)). However, since the licensee has i
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documented the corrective actions to this violation in LER
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341/93006, no response is required.
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(Closed) LER (341/91008) Revision 1:
ESF actuation during
performance of Reactor Vessel Level Transmitter Calibration.
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The inspector reviewed documentation, including.the-
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l licensee's Human Performance Enhancement System (HPES)
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report, associated with the event. The inspector verified
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the LER was completed. The inspectors have no further
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concerns.
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Quality Assurance
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The inspectors were concerned that the licensee's Quality i
i Assurance (QA) organization had not identified the problems with the Potential Design Change (PDC) "at risk" process described in paragraph 6.c of this report.
QA was involved with-both PDCs
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discussed in paragraph 6.c and had the opportunity to identify the l
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One violation was identified.
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5.
Maintenance / Surveillance (62703 & 61726)
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Maintenance Activities (62703)
Routine, station maintenance activities were observed and/or-l reviewed to' ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes or-standards, and with technical specifications.
The following items were also considered during this review:
limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to.. initiating the work; functional testing and/or calibrations were performed prior to returning components or systems.to service; quality control records were maintained; and activities were accomplished by qualified personnel.
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Portions of the following maintenance activities were observed and reviewed:
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e WR 835920720:
" Perform Semi-Annual Preventive Maintenance Tasks, EDG -11" e
WR 839921222:
" Perform Semi-Annual Preventive Maintenance Tasks, EDG -12" l
e WR R310911003:
" Cal Check EDGSW Pump "C" Minimum Flow Pressure Loop" l
e WR 000Z922021:
" Replace Tubing / Fittings to Pressure Switch in EDG-12 Gage Panel" e
WR 000Z931617:
" Extraction Steam line Modification" e
WR E649911003:
" Calibration of HPCI Suction Pressure Switch" Work Requests 000Z931617 and E649911003 installed modifications.
Upon completion of the work, post modification testing was not done in accordance with the applicable Engineering Design Change l
packages.
For further details see paragraph 6.c of this report.
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b.
Surveillance Activities (61726)
During the inspection period, the inspectors observed technical specification required surveillance testing and verified that l
testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that results conformed with technical specifications and procedure requirements and were reviewed, and that any deficiencies identified during the testing were properly resolved.
The inspectors also witnessed or reviewed portions of the following surveillances:
e 24.307.017:
"EDG-14 Start and Load Test - Fast Start" e
24.707.001:
"RWCW Valve Operability Test (G3300 F120 Only)"
e 44.160.002:
" Fire Protection Detection Operability and Functional Test" On Thursday, March 11, 1993, fire protection personnel were
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performing the monthly valve lineup procedure on the Halon System.
During the performance of the valve lineup surveillance procedure, l
the personnel noticed that the actuator on the main Halon tank was disconnected. The situation was reported to the control room and
the actuator was reconnected.
The licensee's initial l
investigation determined that an independent verification required by surveillance procedure 44.160.002 was not performed. This matter will be further reviewed by the NRC.
No violations or deviations were identified.
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6.
Enaineerina & Technical Support (37700)
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System Enaineerina
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Excellent system engineering support / involvement was noted during the EDG 12' outage. This. excellent support allowed the EDG 12
outage to be performed in a well organized manner with no problems being noted. The well organized EDG 12 outage minimized the
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amount of time the EDG was in a limiting condition of operation.
b.
Operability Assessment of G3300F120 The inspectors reviewed the licensee's assessment.of' degraded valve, G3300 F120. This valve is a containment isolation check valve with a spring assist to close. During. surveillance test
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24.707.01, on January 19, 1993,-and March 18, 1993, valve G3300 F120 did not indicate " fully" closed. The licensee performed an-i Inservice Testing (IST) Evaluation,93-004, on January 19, 1993, and concluded that the most probable causes were either internal
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resistance caused by indicator shaft packing drag or alignment-
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drag. The valve was placed on an accelerated test frequency
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(monthly versus every three months).
In February'1993, valve G330
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F120 was successfully tested in accordance with surveillance
procedure 24.707.01. However, on March 18, 1993, the valve again failed to fully close during surveillance testing. The licensee
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then revised IST Evaluation 93-004, to address operability of
valve G3300 F120. The inspectors reviewed Revision 1 of IST
Evaluation 93-004 and determined the technical basis for operability was not complete.
The evaluation stated that l
operability of the valve. disc for G3300 F120 had been sufficiently
demonstrated with both valve position indication and disc stroke being fully operable. However, the evaluation did not address the operability of the valve's actuator.
During the March 18, 1993
surveillance test, the licensee noted that the actuator did not
exercise properly. Since valve G3300 F120 was.a check valve used as an outboard containment isolation valve, the actuator's operability should have been addressed in Revision 1 of the IST Evaluation 93-004. After discussions with the inspectors, the l
licensee issued Revision 2 of the IST Evaluation 93-004. The inspectors reviewed the revised evaluation and determined that the
basis for the operability of valve G3300 F120 was adequately l
documented.
The actuator was replaced on April 13 -114,.1993.
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c.
Potential Desian Chanaes (PDC)
On April 20, 1993, a reactor-trip occurred at approximately 2 percent reactor power. The reactor trip was caused by the failure of both pressure transmitters used in the pressure. regulator for i
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the electro-hydraulic control system for the main turbine. The failure of both pressure transmitters was caused by a steam leak i
blowing steam onto the pressure transmitters.
The steam was
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leaking from a transducer connected to the 52 inch main steam
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i manifold to monitor steam pressure during startup testing.
The startup testing was associated with the modifications to the 4N/4S Feedwater Heater Extraction Steam Line. The modification consisted of removing the expansion joint on the 36 inch extraction steam line at the center low pressure turbine.
The expansion joint was replaced with hard piping. The modification to the extraction steam line was performed by the licensee under the Potential Design Change (PDC) "at risk" process. The PDC "at risk' process allows the installation of a modification prior to the issuance of the final design package (Engineering Design Package (EDP)). The following concerns were identified during the i
l review of the PDC 13893, EDP 13893, and work requests (WR) for the modification to the extraction steam line:
EDP 13893 identified an inservice visual inspection on the connection of the pressure transducers as a post modification test (PMT).
This inservice visual inspection was not identified in WR 000Z930523 that installed the transducer on the 52 inch main steam manifold. The individual who installed the transducer did have the opportunity to inspect the connection when he verified that the plant installed valve was open to place the transducer in service.
This inspection occurred when reactor pressure was approximately 200 pounds per square inch (psi).
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reactor trip occurred at approximately 500 psi.
l e
PDC 13893 did not identify any PMT; however, EDP 13893 did identify the post modification testing (PMT) requirements.
The PMT included a dye penetrant (PT) on the temporary inspection removal port weld on the 4N Feedwater Heater.
The review of WR 000Z931617 and associated documentation determined that a magnetic particle (MT) inspection of the temporary inspection removal port weld was performed rather than a PT.
Even though a PT examination was equivalent with
,
a MT, the inspectors were concerned that a modification was
)
installed under a " Construction at Risk" PDC which had post
'
modification testing not performed in accordance with the EDP.
During the Plan of the Day meeting on April 22, 1993, the licensee discussed a potential problem between the installation of a High Pressure Coolant Injection (HPCI) system suction pressure switch and design criteria acceptance testing (DCAT) defined in a EDP.
This problem was identified by the licensee during a review of PDC packages installed during the extraction steam line outage. This review was performed due to the concerns identified by the inspectors with post modification testing associated with PDC 13893. The inspectors requested a copy of the EDP and, if applicable, a copy of the PDC.
.
l The inspectors reviewed EDP 13907 and PDC 13907 that were issued as a result of being unable to calibrate the installed HPCI suction pressure switch during the performance of 46.000.006 (WR E649911003). The design change was initiated to replace the installed pressure switch with a new model.
The inspectors reviewed the EDP 13907 and PDC 13907 to assess the installation of I
the new pressure switch and had the following comments:
The work to install the new pressure switch was performed e
under the auspices of a " Construction at Risk" PDC. The installation required a modification to the mounting configuration due to the different diaphragm material used in the new pressure switch.
WR E649911003 was revised to install the new mounting configuration and to calibrate the new pressure switch. The original pressure switch was General Electric (GE) part Number 145C30llP003 and the new GE recommended pressure switch was part Number, 188C7267P007.
PDC 13907 used to install the new mounting configuration and pressure switch did not have post modification testing.
EDP 13907 identified post modification testing in the DCAT section of the EDP. The testing included calibrating the new pressure switch in accordance with procedure 46.000.006 and to verify verification of annunciator window 2D55 (low suction pressure).
However, since the new pressure switch was calibrated in the Instrumentation and Control (I&C) shop, the verification of annunciator alarm 2055 was not performed J
for the new pressure switch. The licensee determined that the engineer who signed the Modification Implementation
,
Checklist to accept the post modification testing had erroneously looked at the test results for the originally installed pressure switch.
Subsequent review by the l
licensee determined that the original pressure switch had been successfully verified to activate annunciator alarm
'
2D55 prior to being replaced.
Therefore, a retest did not need to be performed for the new pressure switch, since the switch was properly calibrated in the I&C shop and the relays associated with annunciator alarm 2D55 had already been tested with the original pressure switch installed.
- The inspectors did identify a concern with inadequate post modification testing requirements in EDP 13907.
Besides activating an annunciator alarm for low suction pressure for HPCI, the pressure switch also trips the HPCI turbine to protect the pump on low Net Positive Suction Pressure (NPSP).
EDP 13907 did not require that the turbine trip feature and logic of the suction pressure switch be verified. The calibration of the HPCI suction pressure switch was scheduled for every six quarters. A review of WR E64991103 determined that the turbine trip feature of the
.-
-
_
_ _
pressure switch was unable to be verified during the calibration of the original pressure switch.
Therefore, the HPCI system was returned to service without completely verifying the operability of the turbine trip logic associated with the suction pressure switch. The failure to identify adequate post modification testing for a modification is considered an Unresolved Item, pending further NRC review (341/93006-03)
,
i Based on the concerns identified with PDC " construction at risk" modifications in regards to post modification testing, the licensee
'
suspended use of "at risk" until an indepth review is perform of the process.
"At risk" PDCs for certain modifications, such as those that pertain to plant lighting, can be installed with prior approval by upper management. The use of "at risk" PDCs is considered an Unresolved Item
.pending further NRC review (341/93006-04).
,
No violations or deviations were identified.
7.
Report Review During the inspection period, the inspector. reviewed the licensee's Monthly Operating Status Report for February and March, 1993. The inspector confirmed that the information provided met the requirements of Technical Specification 6.9.1.6 and Regulatory Guide 1.16.
The inspector also reviewed the licensee's Monthly Performance Monitoring Report for February, 1993.
No violations or deviations were identified.
8.
Inspection Followuo Items T
Inspection Followup items are matters which have been discussed with the licensee, which will be reviewed by the inspector, and which involve some action on the part of the NRC or licensee or both. An Inspection J
Followup Item disclosed during the inspection is discussed in paragraph 4.a.
9.
Unresolved Items Unresolved items are matters about which more information is required in
order to ascertain whether they are acceptable items, violations, or deviations.
Unresolved items disclosed during the inspection are discussed in paragraph 6.c.
10.
Meetinas and Other Activities a.
Management Meetina On April 28, 1993, the licensee and NRC management (denoted in
,
paragraph 1) met in the NRC Headquarters office for a periodic
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i management meeting. Topics discussed included: plant status,
'
extraction steam line; independent verification; and staffing
transition plan. The slides used by the licensee during the meeting are attached.
b.
Exit Interview (30703)
'
The inspectors met with the licensee representatives denoted in
,
paragraph I during the inspection period and at the conclusion of i
the inspection on May 3, 1993.
The inspectors summarized the
'
scope and results of the inspection and discussed the likely content of this inspection report.
The licensee acknowledged the information and did not indicate that any of the information
disclosed during the inspection could be considered proprietary in nature.
!
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AGENDA i
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NRC MANAGEMENT MEETING
!
ONE WHITE FLINT NORTH ROCKVILLE, MD
--
!
ROOM 13-B-9 10:00 a.m. - 12:00 noon
!
!
o INTRODUCTION D.
GIPSON (10 min.)
[
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o EXTRACTION STEAM LINE
~P.
FFNifRR (45 min.)
I o
INDEPENDENT VERIFICATION PROGRAM J.
PLONA (20 min.)-
I o
REORGANIZATION
.
R.
STAFFORD (15 min.)
o CLOSING REMARKS D.
GIPSON (5 min.)
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Nozzle, Bellows, andPipe with elbow
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Pipe support welded to extraction line l
Natural frequency approxima tely 9 hz l
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Failure Analysis
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Pipe support design provided a high stress concentration area
Startup/ Shutdown cyclesproduces thermalstresses
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Thermal stressesplus high cycle fatigue causedfailure i
Pipefailed atpipe support l
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Pipefailure causedbellowsfailure i
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Configuration Nozzle, Bellows, and Pipe with elbow
Pipe support modified (saddle without attachment welds)
Upperrestraint added
Na tural frequency approxima tely13 hz
Failure Analysis Upper restrain t provide " solid " con ta ct poin t
Modifications changed system to a resonant frequency Pressure measurement determined line hadpressure pulse of5lbs at13 hz
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Cyclic stresses ca used fa tigue cracks in pipe Pipe failure caused bellows failure
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Failure ofinner liner resulted in increased vibra tion Cracks reached critical size; Pipe and Bellows failed
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I Bellows andsupportremoved i
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HardPipe configuration to Condenser wall l
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measure pressure in the extraction steam lines and moisture j
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At onelocation the assembly wasincorrectlymade using
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Each assembly was inspected visuallyprior to start-up and at i
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200# steam pressure, and no problems were observed
?
The mis-assembledinstallation leaked steam and damaged i
two transmittersforpressure regulation andresultedin the i
plantscram
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@@@@dd@ read @n @f @2h@rM27treald@m 0,danmedF@sdwmaar00@alse@es9pm Pres Steam pressure on #3 extraction line approximately25 lbs.
- Approximately1/3 of the #4 Extraction Line Steam pressure on #1 & #2 approximatelyatmospheric
Stresses at support on #3 are lower
=
Inspections 3 North & 3 South Extraction Lines
=
Inspectedlines, bellows, welds andlagging 1 & 2 Extraction Lines and Heaters
=
Inspected bellows andlagging Inspections after both events indicate no changes
Plant Restart
Specific holdpoints at 50, 70, 86, and 96% power levels to monitor turbine and extraction line performance
- - -
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Causes Pressure Pulsations not a concern
TechnicalError - Overly ConEdent, Narrow Focus
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Corrective Actions
Lessons Learned
+ Redesigns need to boundpotentialfailures l
+ Investigatenewfailuremodes
-
ReviewEDPProcess l
PersonalAccountability
'
Critique / Lessons Learned
Training
+ PersonnelErrorReduction i
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TechnicalStaffandManagers
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t Root Cause Training
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RestartData Collection andEvaluation
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Independent Review
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PersonalAccountability Critique / Lessons Learned
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Training y PersonnelErrorReduction g TechnicalStaffandManager Trainingincludes Lessons Learned
Design Review i
.
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.
INDEPENDENT VERIFICATION
o Several recent events
,
o Significance
,
Several plant organizations involved
o o
Implementation errors o
Corrective action I
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CORRECTIVE ACTION i
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o Corrective Action Associated With Each Event l
o Accountability and work group meetings conducted.
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o Equipment (field) verifications CO and Halon system actuators verified
-
l preperly installed.
l Fire Protection procedures performed were reviewed.
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Panet/ Rack jumper walkdown
-
System lineup verifications performed.
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o Corrective Action to Prevent Recurrence Fermi documents examined for consistency.
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New procedure written.
Training on program requirements through new procedure.
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REORGANIZATIOX
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AND RESTRUCTURIXG
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OF NUCLEAR GENERATIOX
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M1ssioN STATEMElNT Reorganize and restructure Nuclear Generation to facilitate best-in-class organizational effectiveness, right skilling, increase supervisory span of control and improve communication within the organization.
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RESULTS of XQA OVERSIGHT of STAFFING
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TRANSTIOx PROGRAM
- Ongoing Specific Oversight of STP
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- Qualifications of personnel
- Changes to QA Program
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- Position Descriptions
- Interviews of Personnelin new roles
- Approxiamtely 500 Manhours devoted to this effort to date Effects of STP added to scope of all Audits
- SpecialReorganization Audit planned
? All NQA personnel monitoring for STP-caused problems as perform inspec-tion and surveillance activities
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? Revisions to QA Program were made as organization and responsibilities changed
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TmCAL PROBLEMS IDENTIFIED Documentation of Qualification Requirements being met not in accordance
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with procedure Reulatory Qualification Requirements established above Tech Spec and QA
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Program commitments and inconsistent requirements
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New supervisor not aware of responses due to NQA for Audit / Surveillance
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observations
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Slow-pace of revision to Implementing Procedures
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Work phone numbers not updated in Emergency Notification Duty Roster
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Communication problems
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Problems being identified to responsible individuals and Senior Management
and action is being taken.
Oversightis continuing.
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EFFORTS TO ASSURE A SUCCESSFUL PROCESS
- Monitoring, evaluating, and updating UFSAR organization description charts
? Continual monitoring and updating of Management Policy and Directives Continued update of NRC
Quality Assurance overview
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OVERVIEW OF R1cn1 Sx1tuxc SELECTION PROCESS
- Develop position summary incorporating:
Core skills
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UFSAR requirements
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Training qualifications
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Job specific skills
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- Candidateidentification
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- Candidate selection
- Review of candidate selectio' by:
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EEO
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' Nuclear Generation Management Team
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FINAL RESULTS of STAFFING TRANSmON
- 35 People took VSO
+ One employe volunteered for Corporate Skills Reserve
= 67 people deselected and put in Corporate Skills Reserve effective 4/26/93 COMPLEMENT COMPARISON
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- Approximately 1000 prior to Staffing Transition Program
- Approximately 200 represented employes
- Approximately 800 non-represented employes
- Less than 700 non-represented employes after Staffing Transition -
Program Staffing transition completed 4/23/93 Four weeks ahead of schedule due to some activities being completed in parallel.
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Nuclear Generation
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April 23,1993 M-l
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t Director Pk2rt TectWed Nuclear Assurance Drector Nuclear 1rdning Manager Monoger Manager Nuc. Quosty Assur.
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.N ector Director Oribudsman Superintendert Radiation Protection
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N. W. MIMS, JR.
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Generd Smervisor Director
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Director-Fermi Computer Sves.
S. E. DAVIS
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