ML20199A394
| ML20199A394 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 12/22/1997 |
| From: | Kozak T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20199A378 | List: |
| References | |
| 50-461-97-22, NUDOCS 9801270205 | |
| Download: ML20199A394 (27) | |
See also: IR 05000461/1997022
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION lli
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Docket Nos:
50 461
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License flos:
Report No:
50 461/97022 (DRP)
Licensee:
lilinois Power Company
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Facility:
Clinton Power Gtation
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Location:
Route 54 West
Clinton, IL 61727
Dates:
October 7 - November 24,1997
Inspectors:
T.W. Pruett, Senior Resident inspector
K. K. Stoedter, Resident inspector
D. E. Zemel, Illinois Department of Nuclear
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Safety
Approved by:
Thomas J. Kozak, Chief
Reactor Projects Branch 4
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EXECUTIVE SUMMARY
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Clinton Pow:r St: tion
NRC Inspect'on Report No. 50-461/g7022 (DRP)
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This inspection included a review of aspects of licensee operations, engineering,
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maintenance, and plant support. The report covers a 7 week period of resident inspection.
Operations
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One example of nonconservative decision making was identified for not assessing
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the impact of shutdown risk due to reduced onsite electrical power availability.
Specifically, the Division ll Emergency Diesel Generator (EDG) was removed from
service for maintenance while the Division i EDG was inoperable due to silting of the
service water system (Section 01.1).
One example of a violation of Technical Specification (TS) 3.0.2 was identified due to
the failure to implement a TS Required Action. Specifically, between July 28 and
October 26,1997, an alternate method of decay heat removal was not verified within
one hour and every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter following the declaration of an inoperable
train of residual heat removal. Consequently, component cooling water remained
aligned to the "B" Reactor Water Cleanup Heat Exchanger even though the A"
Reactor Water Cleanup Heat Exchanger was being credited as the heat sink for the
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alternate decay heat removal source (Section 01.2).
NRC involvement was required for licensing personnel to recognize c 10 CFR Part
50.73 reportable condition involving the failure to verify an alternate method of decay
heat removal, an operation or condition prohibited by the plant's Technical
Specifications (Section 01.2).
Two weakness in the implementation of the corrective action program were
identified. The weaknesses involved downqrading the significance of a condition
report without supervisory review and operations, licensing, and corrective action
review board personnel not being familiar with significance criteria associated with
condition reports (Section 01.2).
Improvements were made in sampling of the Diesel Fuel Oil System following the
inspectors' identification that the fuel oil day tanks were inspected for water after
recirculating the day tank to the fuel oil stviage tank (Section 02.1).
The inspectors identified that the low level alarm setpoint for both the Division I and
til fuel oil day tanks were incorrectly stated in the corresponding annunciator
response procedures (Section O2.1).
Quality assurance identified several weaknesses in the adequacy and
implementation of the self assessment and maintenance ru!e programs. The audits
represented an improvement in the quality assurance organization's ability to perform
thorough and probing evaluations (Sections 07.1 and M7.1).-
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Ona cx:mpla of a vi l: tion of TS 3.0.2 was id:ntif. d du] to the f:ilur] to implement
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TS R:quir:d Action. Specific lly, cetions w;re not pursu:d to r:stora tho Division I
and ll electrical subsystems to an operable status, immediately on two separate
occasions. Corrective actions for the first occasion were narrow in focus in that they
failed to prevent recurrence (Section 08.1).
Operations personnel did not ensure that information needed to perform an
operability determination for over-greasing of 480V motors was provided in a timely
manner This demonstrated a lack of plant ownership and leadership by the
operations department and was inoicative of a weakness in the operability
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determination program (Section M8.1).
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Training provided to operations personnel did not include
systems which are
available to reduce containment pressure. Additionally, tho ... ~ s Mcy operating
procedures did not include all systems which may be beneficial in reducing
containment pressure. These omissions contributed to operations personnelin the
simulator main control room not taking ernergency operating procedure actiuns to
reduce cuntainment pressure using available plant systems (Section P1.1).
Maintenance
Work control procedures for outages did not provide guidance on evaluating risk
associated with the daily implementation of the outage schedule. This item will be
reviewed as part cf the NRC 0350 Panel oversight of licensee improvement
programs (Section 01.1).
One violation was identified due to the failure to provide controlled copies of vendor
manuals and instructions for measuring and test equipment. Operations personnel
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were not trained in the use of portable tachometers prior to using the tachometers in
the field (Section M1.2).
inconsistent guidance was provided in Procedure CPS 8170.06, " Maintenance
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Troubleshooting." Section 2.1.2 stated that the procedure may be used as guidance
when troubleshooting under a job stepped maintenance work request (MWR) while
Section 1.0 stated that the procedure should not replace or be used in addition to a
job stepped MWR (Section M1.3).
One violation was identified due to the failure to provide maintenance work
instructions for repairing safety related hydramotors as required by procedures.
Additionally, the use of a MWR with broad instructions instead of a procedure with
specific hydramotor repair and overhaul guidance was considered a weakness
(Section M1.4).
While problems were noted with the procedure for hydramotor work, it was
considered a positive step thu work was stopped on two occasions so that
procedural instructions could be modified.
The licensee's corrective actions in responso to a previously identified motor over
greasing issue were narrowly focused and untimely in that multiple departments
failed to recognize the potential generic implicat ons of the over greasing issue until
seven ueeks after the initial concem was identified (Section M8.1).
ErLoineerino
Although trending of equipment deficiencies was not actively performed in the past,
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the Cngineering dep;rtment was taking cction to identify cdv rse trends in cquipment
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perform:nce (S ction E1.1).
Plant Suppm1
A number of problems were identified with operator performance during the off hours
emergency exercise. Simulator main control room personnel failed to recognize a
loss of al! DC control power, did not attempt to restore the reactor core isolation
cooling system, did not initiate the standby gas treatment system as required by the
emergency operating procedures, did not effectively communicate priorities, and did
not perform periodic site wide announcements (Section P1.1).
During the drill, the shift supervisor / command authority did not consult with security
personnel to determine if an alternate response location should be established for
personnel in the emergency response organization. This was considered significant
in that the effectiveness of the emergency response organization could have been
signif;cantly compromised during an actual security threat event (Section P1.1).
1he shift supervisor's efforts to provide auditional supervisory oversight during the
exercise were prudent in that he recognized degrading command and control of
activities in the simulator control room and inserted himself in the decision making
processes (Section P1.1).
Performance in the technical support center during the off hours exercise was poor
in that personnel did not recognize when minimum manning reqtsirements were met,
did not ensure priorities for restorstion of plant equipment were communicated, did
not ensure field teams were accounted for, did not update status boards with
information regarding field teams and degraded equipment, did not adequately
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reference emergency operating procedt:res, and transmitted inaccurate information
concerning system availabiiity due to the use ofinformal communications (Section
P1.1).
Licensee drill observers did not critically assess performance during the off hours
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exercise in that several problems were either not recognized or were inappropriately
classified as positive attributes by evaluators (Saction P1.1).
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Report Details
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Summary of Plant SMigg,
The plant remained shut down throughout the inspection period. Significant work completed
included the removal of silt from the shutdown service water portion of the intake structure
and the refurbishment of Division 1 Westinghouse 4160V breakers,
i. Operations
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Conduct of Operations
01.1 Shutdown Risk Assessment
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IDIAcction Scope (71707)
The inspectors reviewed the licensee's assessment of shutdown risk for removing
the Division II Emergency Diesel Generator (EDG) from service on October 13,
1997, to parform maintenance. The inspectors also reviewed procedures related to
planning and scheduling of maintenance while shutdown including: Procedures CPS
1131.01, " Work Control Program;" CPS 1151.01, " Outage Management;" CPS
1151.02, ' Maintenance and Forced Outages;' CPS 1151.04, * Planned Outage
Scheduling;" CPS 1151.08, "Plannhg and Scheduling Department Organization and
Responsibilities;" and
CPS 1151.09. * Methodology for Outage Safety Reviews."
b.
Observations and Findinas
On October 3,1997, an independent evaluator identified that acceptance criteria did
not exist for sitt levels in the service water intake structure and that portions of the
intake structure had not been inspected for sitt. On October 10, the licensee
determined that the acceptance criteria for the maximum acceptable level of sitt in
the area of the shutdown service water system (SX) intake was four inches and that
the exact impact of excess silt on the SX system was unknown.
On October 13, the licensee determined that the area surrounding the Division 11 SX
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pump suction had silt levels from 412 inches deep. The area surrounding the
Division l SX pump suction was not inspected due to diver safety concems; however,
the licensee assumed the sitt levels were similar. The resolution of issues involving
the reliability of the SX system will be reviewed as part of the NRC Manual Chapter
(MC) 0350 Panel oversight of licensee improvement initiatives.
On October 13, the licensee removed the Division 11 EDG from service to perform
breaker maintenance even though they were aware of the degraded condition of the
SX system. -The planned duration of the maintenance interval was 4 5 days.
On October 14, the licensee declared both Division I and ll EDGs inoperablo but
available due to the inability to asses. the impact that sitting near the Division I and
ll SX pump suctions had on SX system performance and on continued EDG
operation.
On October 14, the inspectors questioned the Assistant Vice President / Interim Plant
Manager, the Planning and Scheduling Director, and the Assistant Plant Manager -
Operations to determine whether or not a shutdown risk assessment had been
performed prior to physically disabling the Division 11 EDG. The inspectors were
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concern d that th3 licens:e had not oveluat:d or d:v: loped a conting:ncy pl:n
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which would assure th:t d:f nse in d:pth was maintain:d for onsit3 slectrical power
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distribution giv:n tho d: grad:d condition of the SX syst:m, th) Division ll circuit
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breakers, and the Division I, ll, and IV battery chargers.
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The inspectors noted that the Assistant Vice President / Interim Plant Manager was
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unaware of the circumstances involving the removal of the Division ll EDG from
service and that the decision had been made by his direct reports. After becoming
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aware of the maintenance activity, the Assistant Vice President / Interim Plant
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Manager directed that the Division ll EDG be restored to service since adoquate
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defense in depta for maintaining an onsite electrical distribution division was not
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maintained
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The inspectors were informed by the Assistant Plant Manager - Operations and the
Planning and Scheduling Director that the decision to remove the Division ll EDG
was based on a desire to increase the reliability of the onsite electrical distribution
system oy completing breaker repair activities and to meet the intent of the TS
regarding immediate restoration of plant equipment. In addition, they believed that
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the Division I EDG remained available since it could be started if needed,
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The inspectors questioned operatio_ns and planning personnel to determine why the
Division i EDG could be considered available if the extent of the silting problem in
the SX system was unknown. Operations and planning personnel acknowledged
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that they had not fully evaluated the impact of sitting on long term operation of the
SX system and continued availability of the EDGs. The inspectors determined that
not assessing the impact of decreased onsite electrical power availability on
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shutdown risk prior to the removal of the Division 11 EDG from service was an
example of nonconservative decision making by operations and planning personnel.
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The inspectors reviewed several procedures regarding outage planning and
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scheduling, Of the six procedures reviewed, only one, Procedure CPS 1151.09,
provided substantial guHance on shutdown risk assessment and maintaining
dafense in depth. However, this procedure was intended to only be used during the
development of initial outage schedules and was not utilized during the day to day
iraplementation of maintenance activities. Planning and scheduling personnel stated
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that they had been narrowly focused during the developmont of outage procedures
and thN a review was in progress to improve the work control process.
Improvements in work control processes will be reviewed as part of the NRC MC 0350 Panel oversight of licensee improvement initiatives.
c.
Conclusions
One example of nonconservative decision making was identified for not assessing
the impact of reduced onsite electrical power availability on shutdown risk. Work
control procedures for outages did not provide guidance on evaluating risk
associated with the daily implementation of the outage schedule.
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-01 2 Loss of Confiouration Control for Altemate Shut Down Coolina
a.
Inspection Scope (71707)
- The inspectors reviewed the circumstances involving the October 26,1997, self
disclosing event regarding the alignment of the component cooling water (CCW)
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system to the "B" reactor water cleanup (RT) heat exchanger instead of the "A" RT
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heat exchanger Because the immediate operability of maintaining TS required
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alternate decay heat removal was addressed by the licensee, the inspectors waited
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until
Nov;mber 14, to revbw th3 issue in ord:r to asecrtain th3 cff;ctiv:nsss of rec:nt
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cheng:s in th3 license 3's cortcetivo action proccss.
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Observations and Findinos
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Misaligned CCW For Alternate Decay Heat Removal
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Between July 1 22,1997, alternate decay heat removal was maintained with CCW
aligned to the "B" RT heat exchanger. On July 22, the RT system was shutdown
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and isolated for an emergent reserve auxiliary transformer outage. On July 28, as
part of the RT system restoration, alternate decay heat removal was aligned to the
"A" RT heat exchanger. However, PCW was unknowingly maintained in service to
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the "B" RT heat exchanger.
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On October 26, operations personnel attempted to use the RT system for decay heat
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removal. However, its was identified that the reactor coolant flow was aligned to the
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"A" RT heat exchanger and the component cooling water flow was aligned to the "B"
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RT heat exchanger, Prior to the event, operations personnel believed that the CCW
system was aligned to the "A" RT heat exchanger. Operations ' ersonnel aligned
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CCW to the "A" RT heat exchanger and initlated condition re 'oc (CR) 1-97-10-495.
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The inspectors noted that between August 3, and October 2t,,1997, the "A" RT
system had been credited as an alternate method of decay heat removal pursuant to
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TS 3.4.10 which requires that with one or two residual heat removal (RHR) shutdown
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cooling subsystems inoperable, venfy an alternate method of decay heat removal for
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each inoperable RHR shutdown cooling subsystem within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 24
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hours thereafter. TS 3.0.2 requires that upon discovery of a failure to meet a limiting
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condition for operation (LCO), the Required Actior6 of the associated Conditions
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shall be met. The inspectors determined "1at the required actions for verifying an
alternate decay heat removal method were not performed in that the licensee did not
vNfy the alignment of the CCW system to the "W RT heat exchanger. The failure to
implement the Required Actions of the associated Condition is a violation of TS 3.0.2
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VIO (50-461/97022 01).
Licensee Evaluation of the Event
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The shift supervisor initially classified CR 1 97 10-495 as 'other." Procedure
CPS 1016.01, " Condition Reports," defines "other" as an item which is not significant
but merits trending, investigation, and/or corrective action. On October 30, the
corrective action review board (CARB) reviewed the CR and raised the classification
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to *potentially significant," pending a review by licensing personncI for reportability
and operations personnel for potential programmatic deficiencies with valve lineups.
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"Potentially significant" is defined in Procedure CPS 1016.01 as an interim
classification used when additional information is required to clarify the significance
of the occurrence.
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- On November 3,liconsing personnel responded on the CR generic comment sheet
that,"the misalignment of CCW was not reportable because, while CCW was not
properly lined up to the "A" RT heat exchanger, the condition was recognizable by
operations and could have been corrected before TS limits were exceeded.
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Because this condition could have been recognized and corrected, this condition
alone could not have prevented the fulfillment of the RT system's safety function.
-Therefore the event was not reportable by the requirement of 10 CFR 50.73."
Because licensing personnel did not believe the item was reportable, they
recommended _ that the CR be downgraded to other,
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On Nov:mber 14, the inspect:rs questioned licensing personn:1 on the r: port bility
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of th3 failurq to v rify cn alt: mate d: cay h::t r:mov:1 method pursu:nt to 10 CFR
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Part 60.73(a)(2)(1)(B), an operction or co,,dition prohtait:d by tha pl:nt's TS. The
Director . Licensing stated that the reportability evaluation had been based on
whether or not there was a loss of safety function and not if a condition prohtbited by
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TS had occuned. Following the discussion with the inspectors, the Director -
Licensing stated that a licensee event report should have been submitted for the
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failure to provide an alternate method of decay heat removal for an inoperable RHR
subsystem. The inspectors noted that the required report to the NRC would likely
have not been made within 30 days without NRC involvement.
On November 12, operations personnel responded on the CR generic comment
sheet that,"the misalignment of CCW was an error in proper implementation of the
lineup for restoration of the system following the clearance of a tagout, not a
programmatic issue with valve lineups. The frequency of discovery of mispositioned
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valves versus the valve lineups has remained relatively constant sin':e 1994."
Operations personnel deterrnined that a generic problem did not exist with valve
lineups and recommended that the CR be downgraded to other.
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On November 18, the inspectors reviewed the licensee's investigation report
regarding the CCW system misalignment and noted that the investigator determined
that the misalignment occurred due to inadequate guidance in the system operating
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procedures. Based on discussions with operations personnel, the inspectors
- determined that the individual who provided the comments specified on the CR
generic comment sheet had not reviewed the investigation report. Additionally, the
CCW valves involved in the event had never been tagged as part of a clearance.
The inspectors also noted that the response to the potentially significant CR did not
receive a review by operations management. The inspectors considered not
providing a departmental supervisory review of recommendations to downgrade the
potentially significant CR to other a weakness in impleme-tation of the corrective
action program.
Procedurt CPS 1016.01, Appendix B, " Significance Criteria," provides criteria for
when a ',R is to be censidered "significant." The inspectors noted that the CCW
misangnment met two of the significance criteria which included: alignment errors
(such as valve mispositioning) that result in a failure or potential failure of equipment
to perform its intended function and conditions which result in a non routine report to
the NRC per
10 CFR Part 50.73. Significant CRs require that a root cause analysis and
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corrective action plan be developed and approved by the CARB The failure to
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identify the CCW misalignmut as a significant condition is an additional example of
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- a weakness in implementation of the corrective action program in that operations,
licensing, and CARB personnel were not aware of factors effecting the significance
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determination for CRs.
c.
Conclusions
One violation was identified for the failure to implement the Required Actions of the
associated Condition in that an alternate method of decay heat removal was not
verified within one hour and every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter following the declaration that a
- train of RHR was inoperable. Two weakness in the implementation of the corrective
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action program were identified which involved the downgrading of the significance of
a condition report without supervisory review and operations, licensing, and
corrective action review board persontv not being familiar with significance criteria
associated with condition reports.
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NRC inv:lv: ment w:s r;quir:d f:r licensing personnel to rect,,
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50.73 r: portable conditi:n inv:lving th3 failuro to v:rify alt: mate acay neat r:mov 1,
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cn operation or condition prohibit:d by the plant's TS.
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Operational Status of Facilities and Equipment
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02.1
Inspection of Diesel Fuel Oil (DO) System (71707)
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The inspectors reviewed applicable documents related to the DO system and
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performed a system walkdown. The inspectors questioned the system engineer
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concerning checking for accumulated water in the day tanks following diesel
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ope % tion instead of before since the water in the day tank would not have time to
settle out of solution prior to performing the check. The system enginent agreed that
a more accurate assessment could be made if the check was performed prior to
starting the diesel and initiated comment control fomis to ensure that future checks
for accumulated water in the fuel oil day tank were perforrr.ed prior to starting the
diesel generator. The inspectors also identified that the low level setpoints for both
the Division I and lll DO storage tanks were incorrectly stated in annunciator
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response procedures CPS 5060.08, " Alarm Panel 5060 Annunciators Row 8," and
CPS 5064.05, ." Alarm Panel 5064 Annuncistors Row 5." Engineering personnel
documented the discrepancy in CR 1 97 11-062 and the procedures group was
notified of the error. No other concems were identified.
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Quality Assurance in Operations
07.1
Review of Self Assessment Proaram by Quality Assurance
a.
{ nip _getion Scope (7170D
The inspectors reviewed the audit results of a quality assurance evaluation of the
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self assessment program performed between September 29 and October 22,1997.
b.
Observations and Findinas
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Quality assurance (QA) determined that the CPS self assessment program was
ineffective in identifying and correcting deficiencies, that implementing procedures
were inadequate, and that the program had not been adequately implemented.
Based on the findings, the inspectors determined that the audit represented an
improvement in the QA organization's ability to perform thorough and probing
evaluations. Additional reviews to determine the effectiveness of the licensu's self
assessment program will be performed as part of the NRC MC 0350 Panel oversight
of licensee improvement initiatives.
c.
Conclusions
OA aantified several weaknesses in the adequacy and implementation of the self
assessment program. The audit represented an improvement in the QA
organization's ability % perform thorough and probing evaluations.
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Miscellaneous Operations issues (92901)
08.1
(Closed) LER 50-461/97-024: Improper implementation of immediate TS Action
Statements. On September 12,1997, a member of the independent safety
engineering group initiated CR 1-97-09-159 to document a potential TS
noncompliance because work associated with an immediate TS action statement
was stopped as part of a plant wide stand down.
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Tcchnical Specification S:ction 1.3 d; fin:s immediat:ly cs 'th] requir:d cetion
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should bc pursu:d without d: lay cnd in a controlled m:nn:r." Bas d upon this
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definition, the lic:nsco d:t:rmir.:d that tne work stopp:ge during the stand down did
not constitute a vhlation of TS since the stand down was initiated due to the staff's
inability to perform work in a controlled manner.
On October 1, the licensee determined that work to restore Westinghouse 4160V
breakers and the Division I and II AC bus electrical power distribution subsystems to
an operable status was not pursued immediately as required by TS 3.8.10,
" Distribution Systems Shutdown," Action A.2.4. Specifically, breaker work was
stopped from
August 30 through September 1,1997, in order for workers to observe a ho'iday
weekend. Members i plant management, operations, and work control failed to
recognize that the breaker work was bcing performed to comply with an immediate
action statement. CR 1 97 10-025 and LER 50 461/97-024 were generated to
document this event.
Corrective actions for this event included ensuring that site personnel were aware of
how to properly implement a lor g term immediate TS action statement,
communicating to plant schedulers and the work control team that activities
associated with immediate action statements should proceed without interruption,
and irnproving communications to ensure that both management and staff personnel
were aware of work that was being performed to comply with immediate action
statements. Only one corrective action, placing an article in the site wide newsletter,
remained to be completed after October 10,1997.
On October 27, the operations department initiated CR 1 97 10-481 when licensee
personnel identified that work on Westinghouse 4160V breakers was interrupted on
October 1213 due to improper priority being placed on work activities. Specifically,
the task manager for the breaker work al' owed maintenance personnel to stop
working on the breakers in order to provide additional time off even though there was
breaker work remaining to be performed. The task manager did not consult witri
operations personnel prior to making the decir.lon to stop the work, in addition, the
task manager did not understand that the breaker work was required to be pursued
without delay in order to comply with TSs 3.0.10 and 3.0.2.
On November 13, operations initiated CR 1 97-11 264 to document that work on the
Division i SX Room Cooling Coi! Cabinet was interrupted inadvertently due to the
failure to recognize that this work was being performed to comply with a TS
immediate action statement. Although 6 weeks had elapsed since the first example
of a failure to comp'y with an immediate action statement, some maintenance
personnel were unaware that actions related to immediate TS action statements
were required to be pursued without delay, When operations personnel identified
that work on the cooling coil cabinet had been stopped, they initiated actions to bring
additional workers in such that the work could be completed.
On November 17, licensee personnelinitiated CR 1 97 11-351 to document an
adverse trend regarding proper implementation of TS immediate action statements.
At the conclusion of the inspection period, the licensee was planning to perform a
detailed root cause analysis to determine the cause for the improper implementation
and to develop effective corrective actions.
TS 3.0.2 requires that upon discovery of a failure to meet an LCO, the Required
Actions of the associated Conditions shall be met. The immediate corrective actions
for the first event were narrow in scope in that they were unable to prevent
recurrence. Due to the repetitiveness of this issue, the failure to implement the
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Required Actions of the associ:ted Condition f;r TS 3.8.10 is the second cxample of
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o violation of TS 3.0.2.
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c.
Conclusions
One violation was identified for the failure to implement a TS Required Action in that
the licensee did not pursue a.tions to rettore the Division I and ll electrical
distribution subsystems to an operable status immediately. The actions taken in
response to an event identified on October 1 were narrow in scope in that they were
unable to prevent recurrence.
Il Maintenarig.g
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Conduct of Maintenance
M1.1 General Comments (61726 and 62707)
The inspectors observed or reviewed the following maintenance and surveillance
activities:
MWR D78136
Perform Repairs to Hydramotor
OFZVG104
MWR D81120
Tube Plugging on Main Control Room
Chiller 'A'
MWR D81501
Troubleshooting Main Contro! Room
Chiller "A"
Procedure CPS 6423.04
Determination of Diesel Fuel Oil Contamination
Procedure CPS 9071.01C001
Diesel Driven Fire Pump Weekly Op. Checklist
Procedure CPS 9080.12
Diesel Fuel Oil Transfer Pump Operability
Procedure CPS 9333.40
Division 1114610V Bus Undervoltage Relay Test
Procedure CPS 9431.12
APRM Channel Calibration
Procedure CPS 9981.01
Diesel Fuel Oil Samplirg and Analysis
M1.2 Performance of Diesel Driven Fire Pumo Testina
a.
Inip_fction_Sggpe (61726)
The inspectors observed the performance of Procedure CPS 9071,01C001, " Diesel
Driven Fire Pumps Weekly Operability Test Checklist."
b.
Observations and Findinas
Step 8.1.4.4 of Procedure CPS 9071.01 required the operator to ensure the engine
was idling at a pre-determined speed using a hand held tachometer. The operator
reviewed the vendor documentation provided with the hand held tachometer prior to
its use. When the inspectors asked why the operator needed to refer to the
documentation, the operator responded that he had not received formal training in
use of the device. Not training personnel on equipment used during the performance
of surveillan J testing was considered a weakness in the operator training program.
The inspectors questioned why a hand held tachometer had to be used instead of
the tachometer installed on the diesel engine. The operator stated that the installed
tachometer was known to be inaccurate so a hand-held device was always used.
The inspectors reviewed the MWR database to determine !f the inaccurate
tachometer had been identified on an MWR and determined that a corrective
11
m: int:n:nce document for th3 installed tachomet:r did not cxist. Aft:r furth:r
discussions with operations personn:1, the inspectors learn:d that tho installed
t:chom:t:r was curr:ntly functioning properly. Howev:r, since th] install:d
tachometer had exhibited problems in the past, a decision was made to use a hand
held tachometer during the performance of this surveillance. The decision to use an
alternate tachometer instead of the tachometer installed on the engine demonstrated
operation's lack of confidence that this piece of equipment would properly perform.
10 CFR Part 50, Appendix B, Criterion VI, requires that measures be established to
control the issuance of documents, such as instructions, procedures, or drawings,
which prescribe all activities affecting quality. The inspectors noticed that the vendor
manual provided with the tachometer when it was issued from the measurement and
testing equipment (M&TE) check out area was not a controlled document. A review
of all other vendor manuals in the M&TE check out area determined that they
likewise were not controlled. The failure to ensure that vendor information is
controlled apprt,priately prior to distributing the information for use in the field is a
violation of 10 CFR Pad
Appendix B, L ..
n VI (VIO 50-461/97022-02).
c.
Conclusions
One violation was identifit. due to the fail'Jre to provide controlled copies of vendor
manuals and instructions for measuring and test . quipment. Operations personnel
were
not trained in the use of portable tachometers prior to using the tachometers in the
field and exhibited a hck of confidence in the installed tachometer due to previous
problems with the device.
M1.3 Troubleshootino of Safety Related Eauipment
a.
Inspection Scope (62707)
The inspectors observed electrical maintenance (EM) technicians during the
performance of troubleshooting on the oil pump for the "A" Main Control Room
HVAC Chiller. The procedures and MWR utilized by the EM technicians were
reviewed for adequacy and compliance with upper tier documents.
b.
Observations and Findinag
Through a review of the MWRk, the inspectors determined that it contained generic
steps such as " Troubleshoot control circuitry to determine cause for oil pump start..."
and " Troubleshoot oil pump and related system components ;o determine reason for
excess pump noise." No references to specific procedures for performing the
troubleshooting were noted and directions in the work package stated that the
package was to be returned to maintenance planning following identification of the
problem.
The inspectors were concemed about the lack of specific guidance provided to the
EM technicians in the work package. In d' ~1ssions with maintenance planning
personnel, the planners informed the inspectors that the appropriate way to perform
troubleshooting was with a job stepped MWR.
Procedure CPS 1029.01, " Preparation and Routing of Maintenance Work
Documents," Section 2.2.30, states that " Guidance on troubleshooting is found in
(Procedure)
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CPS 8170.06, ' Maintenance Troubleshooting'." The inspectors r;vhwed Procedure
CPS 8170.06 cnd found that th3 guidance on how to perform troubleshooting was
'
inconsist:nt. For example, S:ction 2.1.2 of Proceduro CPS 8170.06 stst:d, "This
l
procedure may be used as guidance when troubleshooting under a job stepped
~
MWR. However, an MWR is not required...." Conversely, Section 1.0 stated, "It is
t
not the intent of this procedure to replace or be used in addition to a job stepped
l
i
MWR."
When the conflicting requirements found in Procedurs CPS 8170.06 were shown to
,
maintenance planning personnel, the planners were no longer sure of the
'
appropriate mechanism to use to develop and implement troubleshooting plans. ' The
maintenance planning supervisor stated that similar observations were recently made
and that corrective actions for this item were being formulated,
c.
Conclusions
'
Procedure CPS 8170/.6 contained conflicting guidance on the use of MWRs to
perform troubleshcoting in that one section stated that the procedure was to be used
as guidance e w'er a jo' stepped MWR while another section stated that Procedure
CPS 8170.06 st suld n .t replace or be used in addition to a job stepped MWR.
i
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M1.4 P_qdormance of Maintenance on Hydramotor OFZVG104 - MWR D78136
1
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a.
Inspection Scope (62707)
1
The inspectors observed preventive and corrective maintenance on safety related
hydramotor OFZVG104 for the standby gas treatment system.
b.
Observations and Findinos
On October 21,1997, the inspectors reviewed MWR D78136 for repairing an oilleak
on Standby Gas Treatment System "B" Inlet Damper Hydramotor OFZVG104 and
procedure CPS 8452.04, "NH91 Hydramotor Actuator Maintenance," and determined
that the guidance provided in these documents was inconsistent. For example, the
MWR was job stepped to rework the hydramotor as needed. The job plan was
general and allowed the electricians to do steps they thought were necessary to
effect repairs to the hydramotor. Many job steps included phrasing such as "as
necessary" and "as required" to allow as much flexibility as possible. The inspectors
'
noted that Procedure CPS 8452.04 contained specific repair and overhaul
instructions for hydramotors but was only included in the work package for reference.
.
The inspectors were concemed that the use of broad statements such as "as
necessary" or "as required" could result in maintenance work being uncontrolled and
undocumented. The inspectors questioned maintenance planning personnel why the
MWR Job steps were broadly written when a current procedure contained specific
instructions for repairing the hydramotor. Maintenance planning personnel explained
that a broad approach was provided within MWRs whenever the planner was unable
to determine the exact repairs that needed to be performed. Procedure CPS
1029.01, " Preparation and Routing of Maintenance Work Documents," Section
8.2.6.5, stated "When partial performance of a procedure is required and the scope
of work is aqi known up front, the planner shall add a signature space for
maintenance supcrvision to specify and document in the MWR package the
section(s)/ steps of the procedure to be performed. - The signature space shall be
prior to the job' step whicn requires a partial procedure to be performed." The
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inspect:rs n:t:d that th3 signatura sp:ce w:s ngt previded on the MWR. Also, no
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partial proceduro or section st ps w:re stipulat:d to cff:ct repairs to th3 hydramotor.
The f:llur3 to prepare m:lat:nznce work documents as r quir:d by Procedura CPS
102g.01 is considered a violation of TS 5.4.1 (VIO 50-461/g7022-03).
Procedural instructions provided in procedure CPS 8452.04 were also weak causing
work to be stopped on two separate occasions. On the first occasion, the procedure
was revised to include instructions related to performing field calibrations for
hydramotors connected to ventilation dampers and to ensure propar hydramotor
position for coupling / uncoupling. Work was stopped a second time to add
axeptable tolerances to acceptance criteria because repeatable performance could
!
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not be obtained using the information provided in the procedure. Although the
procedural Instructions were not clear, it was considered a positive step that work
was stopped to have the procedure modified.
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c.
Conclusions
'
On3 vhl: tion was identifi:d du3 to th3 fa' va to provida maint: nance work
instructions as required by procedure. The use of a maintenance work request with
broad instructions in9h]d of a procedure with specific repair and overhaul guidance
i
was considered r rMkness.
M7
Quality Assurance 'n Maintenance Activitieu
M7.1 Review of Maintenance Rule Audit by Quality Assurance
QA performed a review between October 13 and 24,1997 of the implementation of
the maintenance rule program. The QA rev:ew identified that the maintenance rule
program was inadequate and that the implementation of the program was ineff6ctM
The ir.3pectors concluded that QA performed a thorough and probing evaluahn of
M8
Miscellaneous Maintenance lasues (92903)
M8.1 (Open) Notice of Violation 50-461/97019-04: Over-gressing of Division ill SX Pump
Lower Motor Bearing. The inspectors determined that the licensee's correct;ve
actions for this issue were narrowly focused and untimely. Following the September
18,1997, Identification of the over-greasing issue, engineering and maintenance
personnel developed immediate corrective actions to escertain the material condition
of the
Division lli SX pump motor. During the week of September 29,11 days after initial
discovery, additional meetings were held to develop a plan to address other
potentially over greased motors. However, the corrective action plan to address this
concern was not approved and the issue was not resolved in a timely manner.
Between October 25 and 27,4 weeks following the initial discovery, engineering
personnel evaluated the material condition of th6 Division I and ll SX pump motors
and determined that the motors should be inspected. However, no one identified the
need to consider the impact on additional motors greased in a similar manner until 6
weeks after initial discovery. The failure to identify and evaluate potential generic
impacts on safety related equipment demonstmted a lack of safety focus and a
significant deficiency in the implementation of the corrective action program,
improvements in tne corrective action program will be reviewed by the NRC MC 0350 Panel oversight of licensee improvement initiatives.
(,1 early November, licensee management placed an increased focus on restoring
Division I equipment to an operable status. On November 3, the inspectors noticed
that approximately 26 MWRs had been written and placed on the emergent work list.
The MWRs were to meggar several Division I motors to identify any winding
degradation due to over greasing. When the inspectors asked management why the
work was suddenly emergent when the condition was identified seven weeks earlier,
the inspectors were told that the work needed to be performed to restore Divisior I
operability.
The inspectors reviewed the November 4 work schedule and found that the 26
MWRs had been taken off the emergent work list. When the inspectors asked why
the work was no longer emergent, the Assistant Plant Manager - Operations and the
Director .- Planning and Scheduling stated that tha work no longer needed to be
completed on an emergent basis since determining the conditica of Division i 480V
motors was no longer a restraint to declaring Division I operable. The inspectors
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disagreed with this position since it appeared that the Division I motors were
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assumed ta be oper:ble without an cv:lu tion to support th] cpernbility d:cisi:n.
'
B;tw::n Novemb:r 4 - 6 s v:ral lic:ns:3 meetings wera h:Id to d:t:rmhe th3
proper way to resolve the over greasing issue. On November 6, operations
personnel declared all 480V motors inoperable when they determined that the
motors could bc .'egraded due to potential over-gressing. Although operations
personnel were aware that the over gressing issue existed, they had not considered
the potential generic implications of the over-gressing and had waited to receive
additional information from the engineering staff prior to making an operability
decision. Due to ineffective communications engineeling and maintenance
personnel the information was not received until November 6. The failure to ensure
that information needed to pctform operability decisions is provided in a timely
manner demonstrated a lack of plant ownership and leadership by the operations
department.
On November 8, the Assistant Vice President / Interim Plant Manager decided that
numerous 480V motors on all safety related divisions would be opened and
inspected for signs of over-greasing. Although the licensee's current corrective
actions appeared appropriate, the initial untimely resolution of this issue and the
failure to fully communicate and understand the scope of work prior to beginning
work activities was considered a weakness in work control oversight.
111. Enaineerina
E1
Conduct of Engineering
E1.1
Trendino of Hydramotors
a.
Lnspection Scope (37551)
The inspectors reviewed the CR database and the equipment history list to
determine if hydramotor deficiencies were being appropriately tracked by
engineering. The inspectors also reviewed applicable procedures, preventive
maintenance tasks, vendor manuals, preventive maintenance history, and corrective
action requirements,
b.
Obseryptions and Findinas
On October 27,1997, the inspectors reviewed the CR database and determined that
six hydramotor deficiencies had been documented using the CR process in the past
2 years. In addition, the inspectors review of the equipment history list determined
that
53 hydramotor deficiencies had been identified in the last two years ouring the
performance of preventive maintenance tasks. When deficiencies were identified
during preventive maintenance, both maintenance and maintenance planning
personnel implemented a work document authorization (WDA) to complete the
necessary repairs and return the equipment to service.
The inspectors questioned the plant engineering group in an effort to determine why
the hydramotor deficiencies hSd not been classified as an adverse trend.
Engineering personnel explained that a trending organization had existed however,
the organization was disbanded due to re engineering and trending activities were
reassigned as a system engineer activity. Due to the work load of the system
engineers, trending was not being actively performed to determine if adverse trends
existed such that corrective actions could be determined,
16
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On S:pt:mber 19,1996, cngineering personn:I initiated CR 1 96 09 126 13
d:cument th:t th] cngin:: ring department w:s n:t activ:ly performing tr:nding
cctivitts d: scribed in Nuclear St: tion Engin:: ring Dep rtment Procedur] R.0,
" Equipment Failure Trending and Evaluation." Actions to resolve the CR were
delayed due to the need to complete higher priority work activities associated with
refueling outage - 6 and the need to create a position within the engineering
organization to begin trending equipment problems.
On May 27,1997, the engineering department began gathering MWRs, WDAs, and
surveillance failure histories from the last three years to perform an MWR failure
trend analysis. The results of the failure trend analysis were then used to detemline
if any equipment was exhibiting an adverse performance trend. On November 3,
1997, engineering completed the failure trend analysis and identified 40 potential
adverse trends including an adverse trend for hydramotors (see CR 1 97 11-481).
The inspectors reviewed the hydramotor items identified through the MWR failure
trend analysis and were concemed that hyrdamotor deficiencies were not included
when determining if an adverse trend existed. The inspectors discussed their
concern with engineering personnel and learned that plans were being considered to
trend equipment deficiencies after all the equipment failures were appropriately
identified and trended. At the conclusion of the inspection period, the remaining 39
potential adverse trends were being evaluated by the corresponding cognizant
engineer. Engineering personnel planned to documont any kjentified adverse trends
through the condition reporting process to ensure that the trends were appropriately
identified and corrected,
c.
Conclusions
Although trending of equipment deficiencies was not actively performed in the past,
the engineering department was taking action to idt niify adverse trends in equipment
performance such that the trends were appropriate,y identified and corrected.
IV. Plant Support
P1
Conduct of EP Activities
P1.1
Evaluq1lon of Off Hours Exercise
a.
Inspection Scope (71750)
The inspectors observed portions of an off hours emergency exercise in the
simulator and Technical Support Center (TSC) on October 15,1997. The response
of t'.: eecurity organization was not evaluated.
b.
Observations and Findinas
The event progression involved a loss of condensate resulting in a reactor trip.
Following the trip, saboteurs caused a loss of the Reactor Core Isolation Cooling
(RCIC) pump, a loss of the Division I and 11 DC buses, and a loss of service water,
No radiological consequences were includea in the drill scenario.
Simulator Control Room
Eight operations personnel were observed in the at the controls area of the simulator
within 5 minutes following the initiation of the drill. Because of the increase in
staffing, the line assistant supervisor (LASS) had difficulty maintaining effective
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comm:nd cnd contr:1 cf oper;t:r cetions. Specifically, discussions between
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oper; tors involving restor; tion cf cquipment cecurred without the kn:wledge of th]
LASS cnnunci: tor ccknowledgments were n:t altt:ys clearly communicat:d or
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acknowledged by the LASS, and the use of 3 way communicaticns and repeat backs
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were inconsistent.
The LASS performed frequent crew briefings which included a summary of the event
progression and current degraded plant equipment. However, the LASS did not
priontize the restoration of degraded equipment.
The Shift Supervisor appropriately classified the Unusual Event, Alert. and Site Area
Emergency, and ensured timely off site notifications were made. In addition, the
Shift Supervisor's additional guidance and mentoring to the LASS during the event
was good in that it aided in identification and assignment of personnel oarly in the
event.
As the Alert was declared due to a security comprise and the Site Area Emergency
was declared due to occupation of vital areas, the 'oectors questioned the Shift
Supervisor and emergency planning personnel as W vhy the Emergency Response
Organization (ERO) was dispatched to the site instead of an alternate location. The
Shift Supervisor stated that he had not considered an altemate response location nor
had he discussed the issue with the security organization. Emergency planning
personnel stated that had this been a real event, local authorities would have
responded and established road blocks to control access to the facility. The
inspectors noted that discussion of establishing road blocks was not performed
during the exercise. The failure to consider an alternate response location for ERO
personnel was considered significant in that the ability to maintain the emergancy
response functions could have been compromised if personnel were put in danger
during an escalating security event.
Operators demonstrated a lack of awareness olsystem failures and restoration.
Specifically, the simulator control room did not investigate the cause for he loss of
the RCIC system. The lack of a RCIC pump failure investigation was considered
significant in that only one safety related injection source (high pressure core spray)
remained available for maintaining reactor vessellevel.
Operators did not recognize a totalloss of Division I and 11 DC power for
approximately
20 minutes. The loss of DC power remained unrecognized even after operators
were unsuccessful in opening safety relief valves to maintain reactor pressure
control. The failure to recognize the loss of DC power was considered significant in
that indications and annunciators clearly signified that DC power had been lost. The
operators did not note that the inability to operate the safety relief valves was directly
related to a loss of control power.
Two unplanned actuations of plant components occurred when field teams restored
Division I and 11 DC power. During the restoration of Division i DC powcr, the
Division i EDG automatically staited when control power was re-energize 1 The
crew promptly secured the EDG because no cooling water was available due to the
loss of the service water systems fol lowing the explosion in the screen house. Even
though the crew knew DC power was being restored, they failed to recognize that
the EDG would automatically start, This failure was significant in that it
demonstrated a lack of awareness by the operators on the impact of system
restorations on plant operation.
Approximately 25 minutes later, the Division ll EDG automatically started when
18
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Division ll DC power w s restored. One) ag:in th3 simulator control room was
r;quir:d 13 securo th] EDG due to tha loss of s.trvice wat:r. The shift supervisor
st:t2d thet h3 was un:w ra that Division ll DC power w:s in th] process of being
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restored. This failure was significant in that operations personnel failed to take
compensatory actions to prevent the automatic statt of the Division ll EDG even after
they had recently been required to take mitigating actions for Division 1.
,
Due to a loss of cooling water, containment temperature and pressure slowly
increased until the crew manually initiated containment spray at 2.2 psig in
containment. On October 18, the inspectors questioned the licensee to determine if
a mitigating action could have been taken prior to spraying down containment since
the operators had several indications to verify a radiological event was not in
progress. Operations personnelinitially responded that they were unaware of other
mitigating actions which could be taken.
The inspectors reviewed Emergency Operating Procedure (EOP) 6," Primary
Containment Control," and noted that for containment pressure, a requirement
{
existed to " hold drywell and containment pressure to below 1.68 psig using the
'
standby gas treatment system (SGTS)." The inspectors discussed the EOP
requirement with the Shift Supervisor and a licensed reacter operator and
'
determined that the SGTS had not been initiated.
The inspectors discussed the usage of EOP 6 with emergency planning personnel
and two senior reactor operator instructors from the operations training group on
Octooer 23,1997. The instructors did not view the failure to initiate the SGTS as a
significant concern for the following reasons:
First, the crew tried to mitigate the pressure rise by attempting to restore
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chilled water to containment. This was viewed as acceptable by the
instructors since the loss of chilled water caused the temperature / pressure
rise and the initiation of SGTS only addressed the increased containment
pressure symptom. The inspectors noted that symptomatic based ECH are
intended to be worked concurrently and that while restoring chilled water was
a success path for contalnnient temperature, it did not alleviate the
responsibility of the operators to perform other tasks associated with pressure
reduction.
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S:cond, the instruct:rs stat:d th:t the Cffect the SGTS h:d en lowering
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cont:inment pressure b cimost useless wh;n you hav] cther pri:ritts.
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Specifically, the SGTS is a r;lativ:ly low flow system (apprcxim:t:ly 500 cfm)
on a large volume containment. Therefore, any pressure reduction achieved
would be minimal. The inspectors noted that the instructors did not have an
evaluation to support this position, and, if the impact was minimal, ad'iitional
guidance should be provided to the operators in the EOP.
The inspectors reviewed the EOP Technical Bases, Section 10, " Primary
Containment Control," and determined that the initial action taken to controi
drywell and containment pressure is thu used during normal plant operation-
burping the drywell and venting through SGTS. The first step in tne
drywell/ containment pressure branch thus provides a smocth transition from
general plant operating procedures to EOPs and ensures that normal
methods of primary containment pressure control are tried before more
complex actions. The inspectors determined that the instructors' opinions
>
were inconsistent with the bases for the EOPs.
Third, the instructors stated that insufficient resources sere availab!e in the
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control room to initiate the SGTS and recover important BOP systems such
as station air and cocMg water. Additionally, their position was that initiating
the SGTS was a poor resource allocation since something else would have
suffered. The insWuctors believed that SGTS initiation was a time consuming
evolution which did not provide substantial benefit and therefore was not
worthy of allocating licensed operator resources. One of the instructors
stated that in the past 8 years of training operators he had not observed a
crew attempt to initiate the SGTS to decrease containment pressure.
The inspectors. were later informed by operations personnel that alignment of
the SGTS to containment requires approximately 6-10 minutes. Therefore,
the inspectom determined that the control room misapplied an additional
licensed RO resource by assigning him phone communications with the
operational support center (OSC) instead of EOP mitigating actions.
Additionally, the crew did not seek assistance of licensed ooerators which
were readily available in the OSC. The failure of the operating crew to seek
additional Isensed operator resources was considered significant in that it
hampered implementation of the EOPs. Training on seeking and use of
additional operator resources is an inspection Followup Item (IFI) 50-
461/97022-04.
On October 24,1997, the inspectors discussed the use of EOPs with senior licensee
management. Their preliminary review determined that the operator actions were
acceptable; however, an independent review would be performed to determine if the
EOPs were properly implemented. The licensee believed that the crew effectively
prioritized actions by attempting to restore containment pressure by pursuing
activities to reduce containment temperature w.d thd they ran out of resources to
align the SGTS. Additionally, the licensee stated that operations training may have
cciitributed to a mind set where operators believed that the SGTS was not effective
on pressure reduction.
On October 30,1997, the inspectors again discussed the staff's performance during
,
the exercise with the Assistant Vice President. He acknowledged that the facility had
done a poor job training on the expectations for utilizing the SGTS, that problems
may exist with EOP 6 in that it does not specify all normal plant systems which could
be used to decrease containment pressure, and that his staff should have discovered
the issue prior to NRC involvement. The Assistant Vice President also stated that a
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t:chnical justific tion for not using th; SGTS could in provid:d; howev:r, it would
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not m ka up for tr;ining, confusion on tha usa of th] SGTS or othsr syst:ms, or
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poor pl:nning of cxp:ctations for drills.
The inspectors determined that the '9ilure to implement the EOPs for primary
containment control a significant cc1cem. Negative training was provided to
operators in that they were not exp.cted to implement the reqaired EOP actions for
initiating the SGTS, Additionally, EOP 6 was not adequate in that additional systems
were not specified for containment pressure reduction. The licensee's actions to
correct training on EOP 6 is an inspection Followup ltem IFl (50-461/97022-05).
Technical Support Center (TSC)
The inspectors observed activities in the TSC Oom prior to the arrival of the
emergency response organization until completion of the drill critique. The TSC met
the minimum staff manning requirements 59 minutes following the declaration of an
Alert. However, the TSC Director did not recognize that minimum staff manning
requirements were met until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 22 minutes. At that time, a decision was
made to delay transfer of command authority from the simulator to the TSC until the
shift supervisor completed notifications for the upgrade to a Site Area Emergency.
The TSC assumed command authority at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 29 minutes. The decision to
delay transfer of command authority was considered prudent by the licensee.
However, the transfer could have occurred prior to the upgrade to the Site Area
Emergency if the TSC had recognized minimum staffing had been achieved.
Three TSC briefs were performed during the drill. The briefing interval was based on
a 30-minute period without consideration for changing plant conditions or event
progression. The briefs summarized degraded conditions in the plant but did not
establish priorities for the restoration of plant equipment. Input from the various TSC
program areas was not obtained during the briefs. Consequently, various responses
to the event were developed without a coo dinated plan. For example, Division i DC
power was restored without the TSC kncwing a field team had been dispatched,
service water system status was improperly communicated, and the availability of
service water to RHR was incorrect.
Emergency Plan Implementing Procedures (EPIP) EC-03, "Notificatian of Unusual
Event," EC 04, " Alert, " and EC-05, " Site Area Emergency," each required periodic
status updates over the public address system until the emergency is terminated.
The inspectors noted that periodic site wide announcements informing personnel of
the event progression were not performed by either the simulator or the TSC.
EPIP EC-12. " Emergency Teams," required the OSC supervisor keep the station
emergency director advised of emergency teams status and progress. The simulator
dispatched non-licensed operators on several occasions without consulting with
either the TSC or the OSC. Therefore, the OSC supervisor and the site emergency
director were
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.31
un::wara of the loc;ti:n of th3 non-licensed oper: tors, although non-lic:nsed
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operctors ara consid; rid fi;ld terms which r;quira tracking by tha OSC supervisor.
9
CPS Emergency Plan, Section 2.3.2.5, requhes eat the TSC emergency operations
supervisor assess and evaluate emergency conditions. The inspectors noted that
the EOPs were not referenced by TSC personnel until 51 minutes following
activation of the TSC. Evun then, the EOPs were only reviewed after prompting on
several occasions by the Illinois Department of Nuclear Safety representative. The
inspectors consideced the failure of TSC personnel to review EOPs a significant
concern in that assessment of plant status with regards to the EOPs was not
performed to support the operating crew.
EPIP FE-01, "TSC Operations," Section 4.5.2, requires that the TSC Administrative
Supervisor is responsible for displaying infon% tion on the key events and problem
board and ensuring the data remains accurate. The inspectors noted that status
boards were not updated in the TSC in a timely manner. Specifically, service water
status was added 44 minutes after the explosion in the screen house, secondary
containment data was not specified, field teams restored Division i DC power even
though they were listed as 'Torming," and RCIC was not listed on the major problem
board.
Drill Observer Comments
The inspectors reviewed post exercise entiques, logs, and written comments
provided by the drill observers in the TSC and simulator. One observer was
assigned to monitor control room activities. Positive attributes noted by the observer
in the simulator included: (1) the shift supervisor's oversight of the operating crew;
(2) quick classification of the emergency events; and (3) evacuation of non essantial
personnel. Negative attributes included: (1) recognition of the loss of DC power; (2)
not providing a reason for the NOUE and ALERT classifications when making
gatronics announcements;
(3) communications between the simulator and TSC/OSC; (4) receipt of a phone call
regarding the status of RCIC; (5) and not being prepared for automatic actuations.
No unsatisfactory grades were ass!gned to the crew performance in the simulator.
The inspectors noted that the simulator drill observers did not assess 3 way
communications, annunciator response, establishment of priorities by the LASS, the
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use of an attemate ERO location, the lack of RCIC restoration, or EOP 6 usage.
Given the number of unidentified issues, the inspectors determined that the observer
was either not sufficiently critical or that insufficient resources were used to provide a
meaningful assessment.
The TSC observers noted the following positive attributes: (1) delaying the transfer
of command and contiol from the simulator to the TSC; (2) control of emergency
repair teams; (3) three part communication; (4) communications between security
and the TSC; (5) brainstorming of ideas by engineering; and (6) following EOP
usage by the simulator. Negative attributes included: (1) response _to the TSC; (2)
use of logs; and (3) TSC staff briefings.
The inspectors noted that the TSC observeia did not assess a lack of prioritization of
issues, periodic announcements of event progression, and updating of status boards.
Additionally, the inspectors noted that the observers incorrectly viewed
communications, control of emergency repair teams, and EOP usage as positive
attributes.' Given the number of unidernified or misrepresented issues, the inspectors
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determined that the observers were not sufficiently critical to provide a meaningful
assessment.
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Ex:rci o Critiqu] R: port
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On October 30,1997 th? licens73 issu:d tha final r: port for th] cft:r hours ex:rciso.
The report did not address the failure to attempt to restore RCIC or consider an
alternate location for the ERO. The report also did not assess the ability of the
evaluators to provide a critical evaluation of the exercise even though several
observations were missed (use of available licensed operator resources, EOP 6
usage, establishmant of priorities, site wide announcements, selection of an alternate
ERO location, RCIC restoration, EOP usage in the TSC, and updating of status
boards).
The report considered TSC usage of EOPs and control of repair teams as positive
even though members of ths TSC were prompted on several occasions to review the
EOPs and tracking of non-licensed operator field teams was inadequate.
c.
Conclusions
. Operator performance during the off hoss exercise was poor in that they failed to
recognize or attempt to restore degraded equipment, did not initiate the SGTS as
required by the EOPs, did not effectively communicate priorities, and did not perform
periodic site wide anrouncements. The Shift Supervisor's efforts to provide
additional supervisory oversight during the exercise were prudent.
Training provided to operations personnel and the failure to includ3 in training
systems which rnay be beneficial in reducing containment pressure in the EOPs
contributed to the operators not implementing EOP req" ired actions to control
containment pressure using available plant systems.
Performance in the TSC was rcarginal in that the TSC director did not recognize
minimum manning require. ants, priorities were not effectively communicated, field
teams were not controlled, status boards were not updated, EOPs were not
adequately referenced, and communications resulted in the transmission of
inaccurate information.
The licensee did not critically assess performance during the exercise in that several
observations were either not recognized or inappropriately classified as positive
attributes by evaluators.
V. Manaaement Meetinos
X1
Exit Meeting Summary
The inspectors presenteo the inspection results to members of licensee management at the
conclusion of the inspection period on November 25,1997. 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.
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- Management Meeting summary -
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On N:v:mber 14, members of tha NRC Clinton Ov;rsight Penel met with lilinils Power
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management to discuss the curre
status of several programmatic deficiencies. .The
_ program areas included; preventive maintenance, corrective actions, work control, quality -
assurance, and the development of the Plan for Excellence.-
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PERSONS CONTACTED
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Licenaee -
J. Cook, Senior Vice President
W. Romberg, Assistant Vice President
L. Wigley, Manager - Nuclear Station Engineering Department
R. Phares, Manager - Nunlear Safety and Performance Improvement
J. Palchak, Manager - Nuclear Training and Support
- G. Baker, Manager - Quality 6,:surance
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'J Gruber Director - Corrective Action
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J. Place, Director - Plant Radiation and Chemistry
R. Joyce, Assistant Plant Manager - Maintenance
- M 1Lyon, Assistant P, ant Manager - Operations
~ J. Hale, Director - Planning & Scheduling
W. Bousquet, Director - Plant Support and Services
- J. Sipek, Director - Licensing
INSPECTION PROCEDURES USED
IP 37551:
Engineering Observations
IP 61728:
Surveillance Observation
IP 62707: -
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support and Observations
a
IP 92901:
Followup - Operations
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IP 92903:
Followup - Maintenance
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ITEMS OPENED, CLOSED, AND DISCUSSED.
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Ooened
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50-461/97022-01a,b VIO ' Failure to it,.slement required actions of the associated
condition as required t,y Technical Specification 3.0.2.
50-461/97022-02
Failure to control copies of M&TE vendor manuals used in
performance of work activities.
_ 50-461/97022-03
VIO . Failure to prepare maintenance work documents as required by
' procedure.
504 61/97022-04
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Training on seeking and use of additional operator resources.
50-461/97022-05
IFl
Correction of training on EOP 6.
Closed
50-461/97 024
LER -Improper Implementation of immediate Technical Specification
Action Statements.
Discussed
50-461/97019-04
Over greasing of Division lli SX Pump tower Motor Bearing.
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LIST OF ACRONYMS
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CARB Corrective Action Review Board
CCW Component Cooling Water
- CR
. Condition Report =
DO
' Diesel Generator Fuel Oil System
DRP ' Division of Reactor Projects
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- EM
Electrical Maintenance -
' EOP Emergency Operating Procedure .
EPIP Emergency Plan implementing Procedure
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ERO: Emergency Response Organization
~' LASS' Line Assistant Shift Supervisor
LCO Limiting Condition for Operation
- M&TE Measurement and Test Equipment
- MWR . Maintenance Work Request
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NRC ' Nuclear Regulatory Commission-
'OSC? Operations Support Center
. PDR Public Document Room
- Quality Assurance .
RCIC Reactor Core Isolation Cooling System
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RHR Ret.idual Heat Removal System
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SGTS Standby Gas Treatment System
SSC . Structure, System, or Component -
SX.
- Shutdown Service Water System
TSC ~ ~ Technical Support Center
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WDA ' Work Document Authorization
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