ML20202J130
| ML20202J130 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 01/02/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20202J114 | List: |
| References | |
| 50-440-97-16, NUDOCS 9802230089 | |
| Download: ML20202J130 (21) | |
See also: IR 05000440/1997016
Text
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U. S. NUCLEAR REGULATORY COMMISSION
REGION ll1
Docket No: 50-440
License No: NPF 58
Report No: 50-440/97016(DRP)
Licensee: Centerior Service Company
Facility: Perry Nuclear Power Plant
Location: P. O. Box 97, A200
Perry, OH 44081
Dates: October 4 to December 1,1997
Inspectors: D. Kosloff, Senior Resident inspector
J. Clark, Resident inspector
G. Harris, Senior Resident inspector, Fermi
K. Stoedter, Resident inspector, Clinton
Approved by: Thomas J. Kozak, Chief
Reactor Projects Branch 4
9802230099 980102
0 ADOCK 05000440
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EXECUTIVE SUMMARY
Perry Nuclear Power Plant
NRC Inspection Report No. 50-440/97016(DRP)
This inspection included a review of aspects of the licensee's operations, maintenance,
engineering, and plant support functional areas. The report covers an 8-week period of
resident inspection. One violation of NRC requirements was identified.
Operations
. Thorough preparations were made prior to retuming the unit to power following
refueling outage 6. The startup was well controlled and accomplished without error.
Shift tumovers and briefings were generally thorough and clear (Section O1.1).
The licensee identified that an operator's failure to ensure the reactor water cleanup
(RWCU) leak detection bypass switch was in the bypass position during the
performance ofloss of offsite power testing caused an inadvertent ieolation of the
RWCU system (Section 01.2).
The licensee identified that operating crews did not adequately communicate and
control the inoperable condition of a control rod during their shifts and shift turnovers
which resulted in a control rod movement prohibited by TS (Section 01.3).
- The licensee identified that a Potential Limiting Condition for Operation was not
entered as required due to improper assessment and documentation when the
conditions specified in a TS-required step of a surveillance instruction (SVI) were not
satisfied. The licensee also identified that the SVI was changed without verifying
that the change did not affect past surveillance test results (Section 01.4).
Maintenance
Overall maintenance activities were effective in improving the material condition of
the plant (Section M1.1).
- The safety tag-out for recirculation system flow control valve (FCV) actuator work did
not isolate the FCV from the reactor coolant system and a failure of the FCV packing
occurred during the actuator work. Several protective barriers in the initiation,
authorization, ard work relea:a process broke down to produce a potentially
hazardous situation for workers. Operators had to respond to minimize a personnel
hazard and isolate a reactor coolant leak. Other personnel accumulated radiation
dose during the leak recovery actions. This event resulted in a violation of NRC
requirements. Another tagging error occurred during restoration of a tag-out which
caused an engineered safety feature actuation (Sections M1.2 and M1.3).
- An operator identified that test equipment remained installed on a Reactor Core
Isolation Cooling (RCIC) system valve after testing was complete. However, the
failure of a maintenance worker to consider the need for environmental qualification
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of the valve and to fully communicate the status of the work activity to operations '
personnel nearly resulted in rendering the RCIC pump inoperable (Section M1 A),
- The licensee identified that an incorrect relay was removed instead of the one
specified under a work order. Inadequate self-checking techniques failed to detect a
work planning error and caused an initiation of an isolation signal that was an
unnecessary challenge to the operators (Section M1.5).
Plant Support
The fire brigade responded well to smoke in the Service Building elevator (Section
F1,1).
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Report Details
Summarv of Plant Status
The unit remained in its sixth refueling outage until October 20,1997, when the licensee
began a unit startup. The startup was completed on October 23, and power was increased
until October 28, when full power was attained. On October 29, power was reduced to
about 70 percent to adjust control rod positions and the plant was retumed to full power on
October 30. The unit operated at full power for the rest of the inspection period except for
one minor power reduction for valve testing,
l. Operations
01 Conduct of Operations
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
01.1 General Comments
a. Inspection Scope f71707)
The inspectors observed many pre-job briefings, shift turnover briefings, and many of
the activities that had been discussed at the pre-job briefings. The inspectors also
observed preparations for startup from refueling outage 6 (RFO6), and the
subsequent startup. Continuous inspection was conducted during the plant startup
and initial power increase,
b. Observations and Findinas
Shift supervisors and unit supervisors consistently initiated briefings prior to
significant plant evolutions. Written briefing summaries were used for almost all
briefings. Operations supervisors presented pertinent information to applicable plant
personnel during these briefings. The briefings usually involved considerable
discussion between team members on responsibilities and expectations. A detailed
written plan was developed for the startup, with specific tasks assigned to individuals
in advance to allow them to familiarize themselves with task requirements, and in
some cases, to practice the task on the simulator, in one case, the specific task
description was not adequate (see Section M1.4). Operations personnel were well
prepared for startup activities, and kept supervision informed of abnormal conditions.
Three-legged communications were normally followed during RFO6, plant startup,
and normal plant operations. The control room appeared crowded at various times
during the plant startup. Although no detrimental effects were noted, operations
personnel stated that they were periodically challenged by the amount of activity in
the control room. There were no operator errors during the plant startup and power
ascension.
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c. Conclusions
Thorough preparations were made prior to returning the unit to power following
RFO6. The startup was well controlled and accomplished without error, Briefings
were generally thorough and clear.
01.2 Reactor Water Cleanuo Isolation
a. Insoection Scope (71707)
i
The inspectors reviewed the circumstances and interviewed personnel involved in
the inadvertent isolation of the Reactor Water Cleanup (RWCU) system during the
performance of a Surveillance Instruction (SVI).
b. Observations and Findinos
During the performance of the Division 1 Loss of Offsite Power (LOOP) Tert,
SV!-R43-T1337, Revision 1 (March 1994), on October 10,1997, the RWCU tvstem
automatically isolated due to an incorrect bypass switch position. The SVI requ; ad
the verification of the RWCU leak detection bypass switch in the bypass position.
Contrary to this requirement, the operator conducting the verification failed to identify
that the switch was actually in the normal position, even though its position was
readily visible. Subsequent steps of the SVI initiated ar; RWCU isolation signal and
actuation due to the incorrect position of the bypass switch. There was no actual
plant condition that required an RWCU isolation, and the isolation had no potential or
actual safety consequences. Ti.is personnel error was promptly identified and
reviewed by the licensee through its corrective action process. The issue was
discussed with operations personnel to curb future self-checking failures. Technical
Specification 5.4.1.a specifies, in part, that
written procedures be established, implemented, and maintained covering the
applicable procedures recommended in Appendix "A" of Regulatory Guide (RG)
1.33, Revision 2. Technical Specification 5.4.1.a applies to SVI-R43-T1337and the
failure to follow the SVI is considered a violation of TS 5.4.1a. This non-repetitive,
licensee-identified and corrected violation is being treated as a Non-Cited Violation
(NCV 50 440/97016-01a(DRP)), consistent with Section Vll.B.1 of the NRC
Enforcement Policy. The licensee reported this event to the NRC as an engineered
safety features (ESF) actuation via the NRC Emergency Notification System (ENS).
The licensee appropriately withdrew the report because 10 CFR 50.72 did not
require reporting an invalid actuation of an RWCU isolation.
c. Conclusions
An operator's failure to ensure the RWCU leak detection bypass switch was in the
bypass position during the performance of LOOP testing caused an inadvertent
isolation of the RWCU system.
01.3 Movement of an Inoperable Control Rod
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a. Insoe: tion Scope (71707)
The inspectors reviewed the circumstances associated with and interviewed
personnel involved in a control rod movement that had been conducted in violation of
the requirements of TS 3.10.4 during control rod drive (CRD) testing,
b. Observations and Findinos
On October 14,1997, operators, with the plant in cold shutdown, were preparing for
startup after RFO6. As part of these activities, CRD hydraulic control units (HCUs)
had been serviced. Following HCU restoration, control room personnel commenced
CRD testing. At approximately 1:00 p.m., control room personnel received an i
ennunciator and indication that the HCU for CRD 18-39 had a scram accumulator
leak. The accumulator leak detection equipment was removed from service to permit
nitrogen recharging of the accumulator. This rendered the CRD for Rod 18-39
inoperable. During recharging, a leaking instrument fitting was discovered and l
Instrumentation and Controls (l&C) personnel were called to assist. Day shift
operations personnel failed to provide administrative controls for CRD 18-39 by
ensuring the condition was deficiency tagged, documented in logs, and tumed over
to the oncoming crew. l
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After the 7:00 p.m. shift turnover, rod testing recommenced. At approximately 7:30
p.m., a reactor operator (RO), under direct senior reactor operator (SRO)
supervision, withdrew Rod 18-39 from the reactor core approximately 12 inches, then
inserted it. All other rods remained fully inserted at that time. The RO Snd the SRO
involved in the rod movement each failed to identify that the CRD was inoperable I
due to the accumulator leak detection equipment having been removed from service.
At approximately 10:00 p.m., l&C technicians informed the RO that the scram
accumulator leak detection instrumentation for the CRD 18-39 HCU was isolated.
The operators restored the instrumentation to service and noted that accumulator
pressure was approximately 1340 pounds per square inch - gauge (psig) with reactor
vessel pressure at 0 psig. This was below the TS-required rainimum pressure of
1520 psig. The operators then declared the CRD inoperable, initiated a deficiency 1
tag for the leak and initiated a potential issue form (PIF) for the personnel error. The
ability to scram the rod is a necessary part of reactivity control that is required to be
maintained whenever rods are withdrawn from the core, it was fortuitous that the .
I
accumulator pressure was above the actual reactor pressure so that Rod 18-39
could have been scrammed if necessary. The licensee subsequently investigated
this event, notified the NRC via the ENS, initiated corrective actions and submitted
Licensee Event Report (LER)97-014. Opedions personnel involved were
counseled and other operations personnel were briefed to prevent recurrence.
Technical Specification Limiting Condition for Operation 3.10.4 required that scram I
accumulator pressure be greater than 1520 psig, as referenced in TS 3.9.5, with a j
rod withdrawn from the core. Contrary to these requirements, control Rod 18-39 was
partially withdrawn from the core with scram accumulator pressure less than 1520
psig. This non-repetitive, licensee-identified and corrected violation is being treated
as a Non-Cited Violation (NCV 50 440/97016-02(DRP)), consistent with Section
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Vll.B.1 of the NRC Enforcement Policy.
c. Conclusions
The inoperable condition of the HCU for CRD 18-39 was not adequately
communicated and controlled by operating crews throughout their shifts and during ,
shift turnover. This allowed a control rod movement which was prohibited by TS.
Due to the low pressure in the reactor vessel, the accumulator had sufficient
pressure to scram the rod if necessary.
01.4 Emeraency Diesel Generator (EDG) Operability Determination
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a. Inspection Scoce (37551. 71707 and 92901)
ihe inspectors reviewed SVI-R43 T5367, "LPCI B and C Initiation and Loss of EH12
Response Time Test," Revision 6 (February 1996) and reviewed the licensee's initial
response, investigation, and reporting of a failed TS-required step of the SVI.
b. Observations and Findinas
in response to Generic Letter 96-01, " Testing of Safety-Related Logle Circuits," the
licensee conducted a review of surveillance instruction SVI R43-T5367 which tested,
in part, the EDG loading sequence during a LOOP or loss of coolant accident
(LOCA) event. A procedure reviewer determined that Step 5.1.4.2.1 of the SVI,
which required verification that Emergency Service Water (ESW) Pump 'B" would
start within 18 to
22 seconds after EDG breaker closure, should have been marked with a "$" sign
signifying that it was a TS-required step. On July 21,1997, the SVI was changed to
include this designation.
On October 12,1997, during RFO6, SVI-R43-T5367 was performed. When Step
5.1.4.2.1 was conducted, ESW Pump "B" started 24.6 seconds after EDG breaker
closure, which was outside of the required time period specified in the step.
Operations personnal were informed of the failure to satisfy the conditions specified
in Step 5.1.4.2.1 of the SVI at about 3:30 p.m. Two PIFs were initiated by operations
personnel. The first was initiated at about 4:00 a.m. on October 13; however, a TS
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Limiting Condition for Operation (LCO) or a potential LCO (PLCO) was not initiated
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nor did operations personnel request an EDG operability determination at that time.
A second PIF, 97-2128, was signed by the Shift Supervisor at 9:08 p.m. This PIF
initiated PLCO P97-1057, but this PLCO identified the ESW pump as the concem,
not the EDG, it was not until the aftemoon of October 14,1997, that a PLCO was
initiated for the EDG. Perry Administrative Procedure (PAP) 1105, " Surveillance
Test Control," Revision 8 (July 1995), required, in part, that operations personnel
take immediate actions to evaluate the operability of equipment and enter the
applicable TS LCO when the conditions specified in a "S" denoted step within a TS
SVI are not satisfied.
The licensee also determined that the conditions specified in this step had not been
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satisfied when the surveillance test was performed during refueling outage 5 (RFOS);
however, this was not considered or evaluated by the procedure reviewer when the
SVI was revised in July 1997. Perry Administrative Procedure 0522, ' Changes to
Procedures and Instructions," Revision 8 (June 1996), stated, in part, that the
change process would ensure all proposed changes met the criteria described in the
In-Depth Review Checklist (IDRC) per PAP-0507, ' Preparation, Review, and
Approval of instructions," Revision 11 (June 1996). The IDRC of PAP-0507 required,
in part, that the document containing the proposed changes be adequately detailed
- for verification and sign off of acceptance
criteria, TS acceptance criteria be clearly stated, and that required follow-up actions
be taken when the proposed document identified an adverse impact on completed
activities.
Technical Specification 5.4.1.a specifies, in part, that written procedures be .
established, implemonted, and maintained covering the applicable procedures
recommended in Appendix "A" of Regulatory Guide (RG) 1.33, Revision 2.
Technical Specification 5.4.1.a applies to PAP-0522,0507, and 1105. The failure of
operations personnel to immediately initiate a TS LCO or PLCO for the Division 2
EDG once the conditions specified in a "$" step of an SVI were not satisfied, is an
example of a violation of TS 5.4,1.a in that PAP-1105 required an immediate
operability evaluation and entrance into the applicable LCO or PLCO when Step
5.1.4.2.1 conditions were not satisfied. The failure of the procedure reviewer to
ensure that required follow-up actions were taken when the proposed change to SVI.
R43 T5367 resulted in an adverse impact on completed activities (i.e., conditions
. specified in a ?$' step were not satisfied when the subject SVI was performed during '
RFO5) is an additionst example of a violation of TS 5.4.1.a. Corrective actions
included both engineering and operations personnel required training on the
significance of SVI failures, the need for retrospective review; when changing
procedures, and
the need for prompt equipment operability determinations This non-repetitive,
licensee-identified and corrected violation is being treated as a Non Cited Violation
(50-440/97016-01b and c (DRP)), consistent with Section Vll.B.1 of the NRC
The Division 1 and 2 EDGs were rated at 7000 kilowatts (kw), which was
significantly greater than the loao demand on the divisional busses. The EDG l
maximum expected load during LOOP or LOCA conditions was 5600 kw. Previous
engineering evaluations showed that all buss loads could start at time zero without
sdversely affecting the EDG Further, ESW pump "B" was not needed for cooling
until at least 90 seconds after the EDG started. Therefore, the EDG would not have
been adversely effected by the ESW pump loading at 24.6 seconds. The licensee
indicated that a review of the SVI to determine if Step 5.1.4.2.1 requires a "$"
designation would be completed.
c. Conclusions
The lack of a thorough review of SVI-R43-T5367 before its revision resulted in the
failure to identify that the conditions specified in a step of the SVI designated as TS-
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required, were not satiefied when the SVI was performed during RFOS. In addition,
when the conditions specified in this step were not satisfied when the SVI was
. performed during RFO6, operators failed to recognize that an immediate operability
determination and entrance into the applicable LCO or PLCO was needed. These
problems resulted in the identification of two examples of a Non-Cited Violation.
01.5 Operations Staff Resources
Several operations personnel, including two shift supervisors and a shift technical
advisor, left the licensee's employment during the inspection period. The operation's
department staffing remained above and beyond minimum staffing levels required by
NRC regulations and no immediate concems were noted with the licensee's ability to
effectively operate the plant. Ti.a licensee evaluated this situation and took several
administrative steps to address this situation.
02 Operational Status of Facilities and Equipment
O2.1 Drvwell Closeout
a. Inspection Scope (71707 and 92901)
The inspectors accompanied a plant operations representative for the closeout
inspection of the drywell area of the plant.
b. Observations and Findinas
The drywell was inspected on October 19,1997, with no major deficiencies noted.
The drywell and suppression pool were well prepared for startup. Some minor
debris, such as pieces of duct tape, were discovered by the inspectors during the
walkdown and removed by an operations representative. Other minor debris was
noted in the suppression pocl, and a piece of tape was identified in a safety relief
valve cover. These items were removed by equipment cleaners prior to startup,
c. Conclusions
The operational status of facilities and equipment was appropriately addressed by
operations personnel prior to drywell closecut.
07 Quality Assurance in Operations
07.1 Corrective Action
a.- Inspection Scope (71707) - -
The inspectors evaluated a licensee management initiative to focus attention on
timeliness of corrective actions.
b. Observations and Findinas
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Licensee senior management instructed the corrective action program administrator
to maintain a list of the 20 oldest potential issue forms (PlFs) with incomplete
corrective actions. The list was included in the handout for the daily managers'
meeting and the 10 oldest PlFs were discussed at each meeting, Individuals
responsible for completing corrective actions presented their plans for completing the
actions and identified areas where they needed assistance. When the initiative
began, the oldest PIF was from 1994, at the end of the inspection period the oldest
PlF was from 1995.
c. Conclusions
Licensee management's action and oversight were effective in focusing attention on
-the completion of older corrective actions.
08 Miscellaneous Operations issues
08.1 (Closed) LER 50-440197-12-00: ' Insufficient Procedural Guidance Results In Reactor
Protection System Actuation." On September 23,1997, at about 12:16 a.m., control
room operators repositioned the reactor mode switch without realizing that it would
cause a reactor protection system actuation. This event was discussed in Inspection
Report (IR) No. 50-440/97012. The corrective actions discussed in the LER,
including procedure improvements W operator training, are adequate to prevent
recurrence.
08.4 (Closed) LER 50-440197-14-00: ' Withdrawal ofInoperable Control Rod Results in
Operation Prohibited by Technical Specifications." This event is discussed in
Section 01.3 of this IR.
II. Maintenance,
M1 Conduct of Maintenance
M1,1 General Comments
a. Insoection Scoce (61726. 62707. 71500 and 92902)
The inspectors used Inspection Procedures 61726 and 62707 to evaluate several
work activities and surveillance tests. The inspectors observed emergent work as
well as planned maintenance conducted during the refueling outage, plant startup,
and normal operations.
b. Observations and Findinos
The activities observed were generally accomplished effectively with appropriate use
of drawings and written instructions. Licensee personnel continued to maintain a low
threshold in using the PIF process and equipment deficiency tags to identify issues
and potential problems. This included examples of personnel identifying their own
errors and situations that could contribute to errors or problems that had not yet
occurred. The inspectors observed that design changes were implemented to
a
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impreve the reliability of the reactor feedwater booster pumps (RFBPs). The pre job
briefing for testing the "C" RFBP and placing it in service was thorough and included
clear and detailed communications among operators, maintenance personnel and
engineers. Supervisors emphasized the importance of prompt communications of
detailed observations, conservative decision making, self checking, and proper
preparation. The overall maintenance backlog was reduced and maintained below
the hcensee's long temi goal. An aggressive approach to steam and water leakage
improved radiological conditions and reduced the amount of radioactive effluents-
discharged. The inspectors noted improvements in the maintenance of work records
during the conduct of work, and as a result less effort was required near the end of
RFO6 to gather missing inforrnation to close out work documents,
c. Conclusions
Although exceptions are discussed in this report, overall maintenance activities were
effective in improving the material condition of the plant.
M1.2 Poor Safety Taaaina Led to a Reactor Coolant Leak
a. inspection Scoce (62707. 71707. and 92902)
The inspectors reviewed the circumstances surrour, ding the reactor recirculation
system flow control valve (FCV) packing failure during FCV actuator work.
b. Observations and Findinot
On October 6,1997, with the plant in cold shutdown, contract maintenance workers
were sprayed with reactor coolant as they worked on the actuator for the "A" Reactor
Recirculation FCV in the drywell. The workers were contaminated but no
appreciable dose was received and no personnelinjuries occurred as a result of this
event. Safety tag-out 27868 for work on the "A" FCV did not isolate the work area
from the reactor coolant system (RCS). Before beginning work, the workers asked
their supervisor if the work area needed to be isolated from the reactor cc Mnt
system. The supervisor assumed that the relevant piping was still drained as it had
been the previous day and indicated to the workers that the tag-out was proper.
However, the piping had been refilled and was open to the reactor coolant system.
During the actuator work, the FCV packing cartridge failed and the workers were
sprayed with water. A non-licensed operator observed the water spray (estimated at
100 gallons per minute (GPM)) and notified the control room. The control room
operators promptly closed the maintenance valves for the recirculation loop and the
leakage was reduced to about 10 GPM. The operators did not observe any RCS
level decrease.
Technical Specification 5.4.1.a specifies, in part, that written procedures be
implemented covering the applicable procedures recommended in Appendix "A" of
Revision 2. Appendix "A" of RG 1.33 recommended that safety tagging be
implemented by a written procedure. Perry Administrative Procedure-1401, " Safety
Tagging,"
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Revision 8 (January 1995), required, in part, that tag-outs be prepared and verified to
adequately isolate potential hazards to personnel and equipment prior to the
commencement of work.
Safety tag out 27868 was not adequately prepare ( and verified to isolate personnel
or equipment from the potential hazards associated with the flow control valve
actuator work. This was a violation (VIO 50 440/97016-03(DRP)) of TS 5.4.1.a.
Although this was a licensee-identified and corrected violation, it did not meet the
requirements for enforcement discretion of Section Vll.B.1 of the NRC Enforcement
Policy because it was a repetitive violation. Violation 50-440/97007 01b(DRP),
identified on June 2,1997, occurred because licensee personnel did not adequately
verify that a tag-out adequately isolated a potential hazard to personnel. Also, in the
recent past there have been several plant events and problems that have occurred
because of poor communications. The investigation for PlF 97-1962, which was
initiated for this event, identified 12 contributing factors for this violation; 7 involved
poor communications. In addition to the personnel and equipment hazard
associated with this event, additional personnel radiation dose was accumulated
during the cleanup of the drywell that was required as a result of the spilled reactor
coolant.
c. ConcluJ i ons
The safety tag-out for recirculation system FCV actuator work did not isolate the FCV
from the reactor coolant system and a failure of the FCV packing owurred during the
actuator work. Several protective barriers in the initiation, authorization, and work
release process broke down to produce a potentially hazardous situation for workers. '
Operators had to respond to minimize a personnel hazard and isolate a reactor
coolant leak. Other personnel accumulated radiation dose during the leak recovery
actions.
M1.3 Poor Control of Safety Taaaina Caused ESF Actuation
a. Inspection Scoce (62707 and 92902)
The inspectors reviewed the licensee's evaluation of an ESF actuation that was
caused by incorrect sequencing of a restoration from a safety tag-out.
b. Observations and Findinas
On October 9,1997, with the plant shut down during refueling activities, operators
were removing safety tags from the CRD hydraulic system. Parry Administrative
Procedure-1401, " Safety Tagging," Revision 8 (January 1995), Step 6.4.13, requires
that the tag-out reviewer consider the need to specify an order to be followed when
removing tags. The SRO in charge of removing the tags and resto"ng the CRD
hydraulic system (reviewer) did not adequately consider the order of removing the
tags for tag-out 27835 and when the valves for the CRD hydraulic system were
restored to their normal position, normal leakage filled the scram discharge volumes
until a high scram discharge volume scram occurred. All rods were already fully
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inserted so there was no rod motion. The personnel involved were counseled. The
failure to properly use written instructions appropriate to the circumstances for this
work was an additional example ct a TS 5.4.1.a violation. The corrective actions for
previous tagging errors could not have reasonably been expected to have prevented
this event from occurring. Therefore, this non-repetitive, licensee-identified (as a
result of a self revealing event), and corrected violation is being treated as a Non-
Cited Violation (50-440/97016-01d(DRP)), consistent with Section Vll.B.1 of the
c. Conclusions
Personnel errors in restoring a safety tag-out caused an ESF actuation and resulted
in the identification of an additional example of a TS 5.4.1.a Non-Cited Violation.
M1.4 Improper Control of Test Eauipment
a. Inspection Scope (61726. 62707. and 92902)
The inspectors reviewed the actions associated with the failure to remove test
equipment from a reactor core isolation cooling (RCIC) system motor operated valve
(MOV) following a test.
b. Observations and F!ndinos
Post-outage RCIC system testing included motor operated valve (MOV) testing
during both cold and hot conditions. On Octder 20,1997, the limit switch cover for
MOV 1E51-F0019 was removed to allow the installation of test equipment for the
cold test. Once the cold test was completed, rather than remove the equipment, the
technician left it in place due to the need to perform an additional test on the MOV at
hot conditions. However, in the time between the two tests, the reactor pressure
was to be raised above 200 psig, the pressure above which environmental
qualification (EQ) of the valve is needed. The MOV limit switch cover was required
to be installed to assure EQ of the valve. The decision to leave the cover off, and
the potential inoperability of the valve, were not adequately communicated to
operations. Prior to the reactor pressure reaching 200 psig, this condition was
identified by an operator performing rounds in the area. The test equipment was
removed and the MOV limit switch cover was installed. A subsequent safety
evaluation determined that the RCIC pump was operable because EQ for the valve
was not needed for the plant conditions at the time this condition was identified. It
was fortuitous that the timing of the operator identifying this problE m coincided with
reactor pressure being below 200 psig.
c. Conclusions
The failure of a maintenance worker to consider the need for environmental
qualification of MOV 1E51-F0019 and to fully communicate the status of the work
activity to operations personnel nearly resulted in rendering the RCIC pump
inoperable. However, due to the discovery and removal of the test equipment prior
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to the reactor reaching 200 psig, the RCIC pump remained operable.
M1.5 Incorrect Relav Reolacesi,
a. Inspection Scope (61726. 62707. and 92902)
The inspectors reviewed the actions associated with the replacement of en incorrect
relay under Work Order (WO) 97-1918.
b. Observations and Findinas
On November 20,1997, relay 1821H K4C (labeled "CK") was removed instead of
relay 1C71 A-K4C (labeled 'CD"). Due to a planning personnel error, the WO
incorrectly identified the C71A-K4C relay as "CK." The removal of the incorrect relay
resulted in a half logic actuation of the main steam line isolationi function.
Because ofinadequate self checking techniques, maintenance personnel failed to
detect the work planning error. The event was promptly ident;fied, the correct relay
was replaced, and the isolation was reset. This non-repetitive, licensee-identified
and corrected violation is an additional example of a TS 5.4.1.1 violation and is being
treated as a Non Cited Violation (50 440/97016-01e(DRP)), consistent with Section
Vll.B.1 of the NRC Enforcement Policy.
c. Conclusions
inadequate self-checking techniques failed to detect a work planning error and
caused an initiation of an isolation signal that was an unnecessary challenge to the
operators.
M8 Miscellaneous Maintenance lasues (92700)
M8.1 (Closed) LER 50-440197-007-00: ' Loss of Electrical Power to Reactor Protection
System Bus Due to Electrical Protective Assembly Trip Results in Engineered Safety
Feature Actuations." On July 13,1997, at about 11:58 a.m., electrica. power from
the Division 2 normal power source to Reactor Protection System Bus "B' was lost.
This event was discussed in inspection Report (IR) No. 50-440/97009. The cause of
the event was determined to be unreliable operation of the electrical protective
astembly logic control board. This problem was similar to that reported in LER 97-~
003-00. Completion of corrective actions will be evaluated during the inspectors'
review of LER 97-003-00.
M8.2 (Closed) LER 50-440197-01' ' Loss of Electrical Power to Reactor Protection
System Bus Due to Electr... .,tective Assembly Trip Results in Engineered Safety
Feature Actuations." This re, ilon to LER 97-010-00 corrected an error the licensee
identified in the original LER which incorrectly stated that the event caused a RCIC
isolation. There was no RCIC isolation. Therefore, the event had slightly less
potential safety consequences than originally indicated. Licensee Event Report 97-
010-00 was closed in IR No. 50-440197012 because the corrective actions for LER
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97-010-00 will be evaluated during the inspector's review of LER 97-003-00. This
revision had no impact on that planned review.
M8.3 {Dlosed) LER 50-440/97-011-00: " Technical Specification Surveillance Test
- Performance Results in Engineered Safety Feature Actuations." On September 21,
1997, at about 4:S3 a.m., with the plant shutdown during refueling operations, I&C
technicians performing a surveillance test caused an inadvertent pressure trans!ent
in the reference leg for two level instruments. The pressure transient caused a false
reactor pressure vessel low water level ESF actuation. All safety equipment.
operated as required for the existing plant conditions and there was no adverse
effect on plant equipment. The corrective actions discussed in the LER, including
procedure improvements and l&C technician training, are adequate to prevent
recurrence.
M8.4 LQggn) LER 50-440197-013-00: ' Control Rod Drive Hydraulic System Maintenance
Activities Result in Reactor Protection System Actuations." This LER reported two
similar events regarding safety tagging of the control rcd drive hydraulic system.
The event that involved an ESF actuat'on on October 9,1997, is discussed in
Section M1.3 of this inspection report. No additional inspection is required for that
event. The event that occurred on October 11,1997, is the subject of IR No. 50-
440/97022.
Ill. Enaineerina
E2 Engineering Support of Facilities and Equipment
E2.1 Suporession Pool LevelIndication
a. inspection Scope (37551. 61726. and 92903)
The inspectors reviewed the licensee's initial evaluation of larger than expected
suporession poollevelindication oscillations during a high pressure core spray
(HPCS) system surveillance test,
b. Observations and Findinos
During a surveillance test of the HPCS system, which directed system flow to the
suppression pool v!L the test retum line, control room operators observed that
suppression poollevelindication oscillations were larger than had been observed in
the past. Operators dispatched to the containment to observe the surface of the
- suppression pool determined that the oscillations were not as large as the
instrumentation indicated. The operators documented their observation with PlF 97-
2168. During a discussion with the inspectors, engineers stated that the newly
installed emergency core cooling systems strainer in the suppression pool appeared
to be causing larger pressure oscillations which had been indicated as level
- oscillations by the pressure differential level indication,
in performing its safety function, HPCS would not be retuming flow to the
15
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suppression pool, as it did in the test, so the strainer would not impact the HPCS
safety function. The inspectors and the licensee monitored suppression poollevel
indications during RCIC operation and safety relief valve (SRV) testing because
RCIC and the SRVs discharge steam to the suppression pool when they are
required to perform their safety functions. The inspectors noted only minor variations
in levelindication during RCIC and SRV operations. The licensee performed
another HPCS test with temporary video cameras in the containment and verified
that actual suppression poollevels were not fluctuating more than expected. The
licensee completed its investigation of PIF 97-2168 and concluded that the design of
the level instrument sensing lines allowed an undesirable accumulation of air in the
lines. The licensee concluded that the lines could be vented sufficiently to maintain
the operability of the levelinstruments. However, the licensee developed eight
corrective actions for the PlF, which included development of a more thorough
venting method and evaluation of a modification to the sensing lines. The inspectors
will review the implementation of the corrective actions for this phenomenon during a
future inspection (IFl 50-440/97016-04(DRP)).
c. Conclusions
The accumulation of air in the suppression poollevelinstrument sensing lines led to
indications that level oscillations during a HPCS system surve!llance test were larger
than they actually were.
E2.2 RCIC Govemor Valve
a. Inspection Scope (37551 and 92903)
The inspectors reviewed the trip and troubleshooting of the RCIC turbine during
startup after RFO6.
b. Observations and Findinos
During plant startup and heat up, the RCIC turbine was operated for Inservice
Inspection (ISI). The cold start of the turbine for the ISI was normal, as were other
cold starts. Near the end of the ISI, the RCIC turbine unexpectedly tripped, possibly
as a result of its controls being gently bumped by personnel working on the turbine,
During two immediate attempts to restart the hot turbine, it also tripped. The
licensee delayed plant startup to disassemble the governor valve and thoroughly
investigate the cause of the trips. The investigation revealed that the manufacturing
tolerances of the turbine governor valve stem and carbon spacer rings did not match
design tolerances. The stem was replaced with a component that was acceptable,
but was more susceptible to a previously exhibited corrosion problem. The licensee
completed its corrective action program investigation near the end of the inspection
period and identified several corrective actions. The inspectors need to evaluate the
past operability of the RCIC turbine, the adequacy of corrective actions, the
adequacy of the surveillance testing methods, and the root cause of the failed stem
and spacer rings. This will remain an Unresolved item (URI 50-440/97016-
05(DRP)) until the inspectors complete their eva!uation.
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c. Conclusions
Following unexpected trips of the RCIC tu bine, the licensee promptly completed a
thorough investigation to ensure the RCIC system was operable, issues idenufied
during the investigation require further NRC review.
IV. Plant Sucoort .
F1 Fire Protection Staff Knowledge and Performance
During plant startup, the fire brigade responded to the report of smoke from the
service building elevator. The brigade responded within 2 to 3 minutes and
immediately discovered the source of smoke was the elevator motor. Appropriate
equipment was deenergized, and steps were carried out promptly to secure the area.
No fire was observed. The fire brigade was knowledgeable of the proper actions to
take and demonstrated that their response training was effective.
V. Manaaement Meetinas
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the conclusion of the inspection on December 1,1997. The licensee
acknowledged the findings presented. The inspectors asked the licensee whether
any materials examined during the inspection should be considered proprietary. No
proprietary information was identified.
,
17
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_ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ - _ _ _ _ _ __
PARTIAL LIST OF PERSONS CONTACTED
Licensee
L. W. Myers, Vice President, Nuclear
W. R. Kanda, General Manager Nuclear Power Plant Departrnent
T. S._ Rausch, Director, Quality and Personnel Development Department
N. L Bonner, Director, Nuclear Maintenance Department-
R. W. Schrauder, Director, Nuclear Engineering Department
H. W. Bergendahl, Director, Nuclear Services Department
J. Messina, Operations Manager-
J. T. Sears, Radiation Protection Manager
F. A. Kearney, Superintendent Plant Operations
,
18
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INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observation
IP 71500: BOP-
IP 71707: Plant Operations
IP 71714: Cold Weather Preparations
IP 71750: Plant Support Activities
IP 92700: Onsite Follow-up of Written Reports of Non-routine Events at Power Reactor
Facilities
IP 92901: Follow-up - Plant Operations
IP 92902: Follow-up - Maintenance
IP 92903: Follow-up - Engineering
IP 92904 - Follow-up - Plant Support
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-440/97016-01a(DRP) NCV Inadvertent RWCU lsolation
50-440/97016-01b(DRP) NCV Entering incorrect PLCO
50-440/97016-01c(DRP) NCV Improper Procedure Change
50-440/97016-01d(DRP) NCV Improper Safety Tag Restoration
50-440/97016-01e(DRP) NCV Incorrect Tlelay Replacement
50-440/97016-02(DRP) NCV Movement of Inoperable Control Rod
50-440/97016-03(DRP) VIO Improper Safety Tagging
50-440/97016-04(DRP) IFl Suppression Pool Level Concerns
50-440/97016-05(DRP) URI Unexpected RCIC Turbine Trips
Closed
50-440/97016-01a(DRP) NCV Inadvertent RWCU lsolation
- 50-440/97016-01b(DRP) NCV Entering Incorrect PLCO
50-440/97016-01c(DRP) NCV Imprope; Procedure Change
50-440/97016-01c(DRP) NCV Improper Safety Tag Restoration
19
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50-440/97016-01e(DRP) - NCV -Incorrect Relay Replacement
-
50-440/97016-02(DRP) -NCV Movement of Inoperable Control Rod
50-440/97-007-00 LER- Loss of Electrical Power to Reactor Protection system
Bus Due to Electrical Protective Assembly Trip Results
in engineered Safety Feature Actuations
50-440/97-010-01 LER Loss of Electrical Power to Reactor Protection system
Bus Due to Electrical Protective Assambly Trip Results
in Engineered Safety Feature Actuations
50-440/97-011 00 LER Technical Specification Surveillance T:st Performance
Results in Engineered Safety Feature Actuations
'
50-440/97-012-00_ LER Insufficient Procedural Guidance Results in Reactor
Protection System Actuation
- 50-440/97-014-00 LER Withdrawal of Inoperable Control Rod Results in
Operation Prohibited by Technical Specifications
Discussed
50-440/97-013 00 LER Control Rod Drive Hydraulic System Maintenance
Activities Result in Reactor Protection System
Actuations -
b
(
20
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LIST OF ACRONYMS AND INITIALISMS
CFR Code of Federal Regulations
CRD Control Rod Drive
-EDG Emergency Diesel Generator
ENS Emergency Notification System
EPA ' Electrical Protective Assembly
EQ Environmental Qualification - *
ESF. Engineered Safety Feature
ESW Emergency Service Water
HCU Hydraulic Control Unit
I&C Instrumentation and Control
IDRC In-Depth Reviewer Checklist
@
'
IFl Inspector Followup Item ,
IR Inspection Report ;
KW Kilowatts !
LCO Limiting Condition for Operation
LER Licensee Event Report
LOCA Loss of Coolant Accident
LOOP Loss of Offsite Power
MOV Motor Operated Valve
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
PAP Perry Administrative Procedure
PDR Public Document Room
PIF Potential issue Form
PLCO Potential Limiting Condition for Operation
PSIG Pounds per Square Inch, Gage
RCIC Reactor Core Isolation Cooling
RFBP Reactor Feedwater Booster Pump
RFO5 Refueling Outage 5
RFO6 Refueling Outage 6
RG Regulatory Guide
RI Resident inspector
RO Reactor Operator
RPS- Reactor Protection System
SRI Senior Resident inspector
SRO Senior Reactor Operator
SRV- Safety Relief Valve
SVI . Surveillance Instruction
TS Technical Specification
URI Unresolved item
USAR Updated Safety Analysis Report
VIO Violation
.
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