ML20210M573
| ML20210M573 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 08/11/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20210M545 | List: |
| References | |
| 50-302-97-08, 50-302-97-8, NUDOCS 9708220038 | |
| Download: ML20210M573 (59) | |
See also: IR 05000302/1997008
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
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Docket No:
50-302
License No:
OPR-72
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Report No:
50-302/97-08
Licensee:
Florida Power Corporation
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Facility:
Crystal River 3 Nuclear Station
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location:
15760 West Power Line Street
Crystal River. FL 34428 6708
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ates:
June 8 through July-12, 1997
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-Inspectors:
S. Cahill. Senior-Resident Inspector
T. Cooper-. Resident Inspector
S. Sanchez, Resident Inspector
J. Blake Senior Project Manager -paragraphs M1.6.
M2.1 .M8.2
B. Crowley, Reactor Inspector, paragraphs M1.2 - M1.5
J. Kreh. Radiation Specialist
J. Lenahan - Reactor Inspector, paragraphs 07.1. E3.1
L.- Moore, Reactor -Inspector, paragraphs 07.1. E3.1
L. Raghavan Project Manager, paragraph E3.1
G. Salyers. Emergency Preparedness Specialist,
paragraphs-P2.1.=P3.1 - P3.2. P5.1 - P5.2. P6.1. P7.1
- P7.2
R. Schin. Reactor Inspector, paragraphs 07.2 E3.1
Approved by:
K. Landis, Chief.. Projects Branch 3 -
Division of Reactor Projects
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-9708220038 970811
ADOCK 05000302
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EXECUTIVE SUMMARY
Crystal River 3 Nuclear Station
NRC Inspection Report 50-302/97-08
This integrated inspection included aspects of licensee operations
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engineering, maintenance, and plant support. The report covers a 5-week
period of resident insSection: in addition, it includes the results of
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announced inspections )y 7 inspectors from Region II and the project manager
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from NRR.
Ooerations
The licensee's training for a new revision to the clearance tagging procedure
was adequate. The revision appeared to be adequate to correct some of the
previously observed problems (Section 01.2).
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The licensee's control of a draindown of the reactor coolant system was good
but the requirements and controls for the evolution were scattered throughout
numerous licensee procedures and programs (Section 01.3).
Operations ownership and communications remained a challenge to the licensee,
but licensee management was aggressively pursuing the causes of the problems
in an effort to improve performance (Section 04.1).
The licensee's operability evaluations were adequately justified. However,
the licensee's procedure contained limited guidance for aerforaance of the
operability evaluations. A weakness was identified in tie licensee's
operability evaluation program concerning the lack of detail in the
operability evaluation procedure and the use of unchecked or unverified design
calculations to serve as the basis for operability evaluations (Section 07.1).
A violation (VIO 50-302/97-08-01) was identified for inadequate corrective
action to correct a compliance procedure regarding reportability time clock
requirements, per 10 CFR 50.72 and CFR 50.73 (Section 07.2).
.The inspectors-concluded the licensee self-assessment activities were
effective and specifically that the Corrective Action Review Board had a
definite positive impact on quality of corrective action plans. The inspector
considered this the result of the impact of the new Board members (Section
07.3).
A restart open item to review the license conditions was closed. However,
several noncompliances, that were indicative of poor tracking of regulatory
requirements in the past, were identified as Non-cited Violation (NCV 50-
302/97-08-02). Also, several deficiencies were identified indicating poor
attention to verification of licensing correspondence. poor use of the
corrective action system, and weak expectations for the closure of restart
items (Section 08.1).
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Maintenance
Though activities were generally completed in an acceptable manner, some
weaknesses were observed in coordination of maintenance activities, which had
a negative impact on the completion of certain tasks (Section M1.1).
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The corrective maintenance backlog was still relatively high. but initiatives
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have been implemented to reduce significantly the backlog by September 1997.
Actions to reduce the preventive maintenance backlog have resulted in
significant reductions.
However, there are still 55 equipment tag
calibrations greater than 25% past their due date. The reduction of both the
corrective and preventive maintenance backlogs was being aggressively pursued
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by licensee management (Section M1.2).
All activities observed and records reviewed for repair work on the Main Steam
Isolation Valves were found to meet requirements. Work was performed in a
professional manner in accordance with procedures (Section M1.3).
Good corrective actions had been taken for the previously identified measuring
and test equipment problems (Section M1.4).
Additional exam)les of instruments exceeding their calibration intervals and
another avenue )y which it can occur were identified, indicating continuing
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problems in the preventive maintenance program (Section M1.5).
The licensee's steam generator examination program appeared to be well planned
and well managed (Section M1.6).
The addition of the Reactor B.. iding liner plate condition to the licensee's
restart list was an indication that management appeared to be more directly
involved with the problems associated with the re
Reactor Building coating systems (Section M2.1). pair and replacement of
The controls for painting outside of the reactor building while existing in
licensee procedures, were inconsistently applied. The licensee instituted a
review process to assess and upgrade the control program (Section M2.2),
A lack of questioning attitude and a weakness in procedural controls resulted
in an unexpected trip on a reactor protection system channel (Section M3.1).
The-lack of coordination between the work schedule and the surveillance
procedure schedule created a possible avenue for missing Technical
S]ecification required surveillances.
Surveillance scheduling practices at
t1e site demonstrated weaknesses, identified both by the NRC and the licensee
(Section M3.2).
There was still room for improvement in the ease of use of licensee's
procedure change process as well as control of the system for posting
outstanding comments against procedures (Section M3.3).
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The functional test provided evidence that the emergency feedwater system
cavitating venturies will perform as designed. in restricting pump run-out and
assuring that NPSH will be assured during accident conditions (Section M8.1).
Enoineerina
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The inspectors concluded that the licensee's 10 CFR 50.59 program was good.
The 50.59 procedure and 50.59 evaluations reviewed were generally thorough,
detailed, and comprehensive (Section E3.1).
Plant Suocort
Emergency response facilities were well designed and equipped. and were
maintained at an acceptable. level of operational readiness (Section P2.1).
A Radiological Emergency Response Plan revision was made in accordance with
10-CFR 50.54(q). and three emergency declarations in 1996 and 1997 were made
in accordance with applicable procedures.
Implementing procedures for the
Radiological Emergency Response Plan were thorough in implementing the
requirements and commitments in the Plan (Sections P3.1 and 3.2).
The licensee maintained an adequate Emergency Preparednsss initial training
and annual retraining program.
Lesson plans and examinations were well
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organized and contained good detail. An Inspector Follow-up Item (IFI 50-
302/97-08-03) was identified due to a variance in scenario classification by a
sample of Emergency Coordinators determined to be caused by training
wea<nesses and Emergency Action Level ambiguity (Section P5.1).
The licensee met the drill commitments in their Radiological Emergency
Response Plan.
No degradation had occurred in the organization or management
of the Emergency Preparedness program as a result of many recent plant
management changes.
Emergency Preparedness appeared to be receiving strong
management support at Crystal River (Sections P5.1 and 6.1).
The Quality Assessments audit for 1996 fully satisfied the 10 CFR 50.54(t)
requirement for an annual independent audit of the Emergency Preparedness
3rogram. The licensee was documenting and tracking their drill comments and
Emergency Preparedness commitments.
Premature closure of an item was
identified as a cause for one of the two cases reviewed (Sections P7.1 and
7.2).
A Non-Cited Violation (NCV 50-302/97-08-04) was identified for untimely and
-inadequate corrective actions that resulted in all fire service pumps being
rendered inoperable during the performance of a post maintenance test (Section
-F3.1).
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The inspectors assessed the licensee's performance in the five areas of
continuing NRC concern in the following sections: the assessments are limited
to the specific issues addressed in the respective sections.
NRC AREA 0F CONCERN
ASSESSMENT SECTION
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01.2
04.1
07.1
07.2
07.3
08.1
E3.1
E8.2
Management oversight
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Engineering Effectiveness
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Knowledge of Design Basis
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Compliance With Regulations
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Operator Performance
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5 - Superior G - Good A = Adequate /Acceptab~e I = Inadequate
Blank - Not Evaluated / Insufficient Information
Section 01.2:
Clearance Tagging Procedure Change Training
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Section 04.1:
Operator Performance & Communication Observations
Section 07.1:
Operability Evaluation Program
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Section 07.2:
Reportability Program
Section 07.3:
Licensee Self-Assessment Activities
Section 08.1:
Restart Item to Verify License Conditions Are Met
Section E3.1:
10 CFR 50.59 Safety Evaluation Program
Sect.icn E8.2: (Closed) VIO 50-302/%06-04 Failure to Fbrfmn an Evaluatim in Accorthnce with 10 CFR 50.59 for Vital Battery Charpr Cmfiguratim Diffenst than Described in the Final Safety
Analysis Report
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Report Details
Summary of Plant Status
. The unit remained in Mode 5 throughout the ins)ection period, continuing in
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the outage that began on September 2. 1996. T1e reactor coolant system (RCS)
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was drained to a reduced inventory condition on June 12 to su) port once-
through steam generator (OTSG) nozzle dam installation. The RCS was then
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vented to atmosphere and refilled to a normal level on June 14 and remained in
this condition through the report period to support OTSG eddy current tube
inspections and tube _end repairs. Both OTSG secondary sides remained
completely drained this period for ongoing main steam isolation valve
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refurbishment. Work on several major abysical modifications related to the
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licensee's restart efforts continued tais report period. These included
Emergency Feedwater (EFW) cavitating venturis. EFW motor-operated cross-tie
Valve EFV-12. overpressurization chambers for containment penetration
isolations to address concerns in NRC Generic Letter 96-06. Assurance of
Equipment Operability and Containment Integrity During Design Basis Accident
Conditions. and Feedwater Pump 7 Backup Diesel Power Suppiy.
L. Doerations
01
- Conduct of Operations
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01.1 General Comments (71707)
Using Inspection Procedure 71707 the inspectors conducted routine
reviews of ongoing plant operations whic1 included shift turnovers.
response to problems. plant tours, log reviews, and review of clearance
tagging processes.
Significant observations are discussed in the
following paragraphs.
The inspectors observed that plant cleanliness was much im) roved over
previous observations.
Licensee management attention in t1is area has
resulted in better cleanup of work sites at the end of shift and very
few examples of uncontrolled equipment adrift in the plant.
On June 17. 1997, 230kv Breaker 1159 developed a fault and exploded in
the licensee's 230kv switchyard near the nuclear plant. Adjacent
Breakers 1158 and 1160 tripped o)en on the fault current, isolating
Breaker 1159 electrically from tie remainder of the switchyard,
Although the licensee's emergency bus power was supplied from the 230kv
switchyard, the isolation limited the effect on the nuclear plant to a
momentary voltage dip,
This in turn caused an isolation of reactor
coolant system letdown, a spike on a radiation monitor that isolated
reactor building purge, a trip of some air compressors, and
miscellaneous saurious alarms. The licensee declared a Notice of
Unusual Event (10UE) for the explosion in accordance with their
Emergency Plan and quickly restored the affected functions.
The
inspector verified the effect on the plant was minor and did not
-identify any deficiencies with the licensee's response.
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01.2 Clearance Taqaina Procedure Chanae Trainina
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Insoection Scone (71707)
The inspectors attended and reviewed the licensee * " ~ning on June 20
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for Revision 75 of Compliance Procedure (CP)-115.
Plant Tags and
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Tagging Orders. The licensee revised the procedure to correct several
deficiencies in their clearance tagging system that had resulted in
significant, previously documented problems,
b.
Observations and Findinas
The inspector observed that the training encomaassed all switching and
tagging qualified individuals and was fairly taorough given the diverse
audiences. The inspector observed that the instructor put the changes
in anpropriate context by discussing the multitude of problems that were
the impetus behind the change but he did not sufficiently discuss their
significance. The inspector also observed that the numerous comments
from maintenance personnel questioning their inability to do hands-on
verification of tagged components indicated a distrust of the process
and Operations implementation of it.
Implementation of the revision on
June 27 was adecuate although the licensee identified that several
questions raisec in tiaining sessions were only addressed to the
attendees of subsequent sessions. The licensee corrected the problem by
widely aromulgating the answers via Night Orders and shop briefings.
Althougl problems continued to occur with tagging orders such as the
wrong system nomenclature used on a tag on June 16 that was found in an
acceptance walkdown, licensee management continues to focus significant
attention on tagging issues. The multitude of personnel cognitive
errors has been attributed to a small group of individuals and the
licensee has taken appropriate disciplinary action.
c. Conclusions
The inspector concluded that the licensee's tagging training was
adequate and the revision to CP-115 should correct some of the
previously observed problems.
Further reviews of CP-115 will be
performed when closing outstanding violations on the NRC Restart List.
The inspector assessed the licensee's performance, with respect to this
restart-related issue, in the five NRC continuing areas of concern:
Management Oversight - Good
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Engineering Effectiveness - N/A
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Knowledge of the Design Basis - N/A
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Compliance with Regulations - Adequate
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Operator Performance - Adequate
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01.3 Reactor Coolant Svetem Draindown Controls
a.
Insoection Scoce (71707)
The inspector reviewed the licensee's process and performance of RCS
draindown activities to reduced inventory performed June 9 through June
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14 to install 0TSG nozzle dams,
b.
Observations and Findinas
The inspector observed that the licensee had assigned a single,
accountable Operations individual to coordinate the draindown
activities. This resulted in effective and consistent pre-job briefings
and good preparation for the draindown. The inspector observed that the
licensee did not have an effective. simple operator aid or controlled
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system schematic showing relative RCS levels and reference points. The
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inspector determined this would have enhanced the quality of the pre-job
briefs.
The licensee was researching a suitable aid.
The performance
of the draindown and refill did not result in any significant problems.
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Some minor challenges delayed the licensee's schedule, but the inspector
noted the licensee's decisions were conservative. The licensee only
drained the RCS to a low level of 131 feet (reduced inventory is less
than 132 feet) to drain the Reactor Coolant Pump (RCP) J-legs. This was
above their mid-loop definition of 129 feet 6 inches.
The inspector
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reviewed NRC Generic Letter (GL) 88-17 and verified the licensee's
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procedures and controls met the GL requirements.
The ins)ector did
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observe that the licensee's requirements were scattered tiroughout
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numerous procedures such as various Operations Procedures. Compliance
Procedures, and Administrative Instructions. Although no requirements
were missing or not implemented, the inspector considered this a
potential challenge to the licensee to ensure adherence to all of the
requirements.
The ins)ectors observed a very good example of operator
questioning attitude w1en a licensed operator observed work on an
offsite 230kv line by utility electricians that had bypassed the nuclear
plant controls for ensuring stable offsite electrical power.
The work
was stopped and the cause of the problem corrected.
c.
Conclusions
The inspectors concluded that the licensee's control of the RCS
draindown was good but that adherence to the requirements and controls
for the evolution could be challenging since they were scattered
throughout numerous licensee procedures and programs.
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Operator Knowledge and Performance
04.1 Ooerator Performance and Communication Observations
a.
Insoection Scone (71707)
The inspectors are reviewing examples of Operations performance to
assess the operators questioning attitudes and communications practices.
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Licensee management has focused on improving performance in these areas.
and they are restart restraint items on the NRC Restart List,
b.
Observations and Findinas
The inspectors have observed that coordination and communications
improvement between Operaticm and other site groups was a significant
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priority with the new licensee management team.
Numerous initiatives
such as a new format and expectations for the Daily Schedule
Coordination Meeting, assignment of an extra Shift Manager (SM) to asses
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Precursor Cards (PCs) which freed the onshift SM to oversee plant
evolutions and reinforced expectations of Shift Supervisor ownership and
cognizance of significant evolution briefings were indicative of this
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priority. Questioning of 230kv line work discussed in the RCS Draindown
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Section, good Operations concern on controlling access to operable
diesel generator rooms on tours and for scaffolding work, and several
good questioning and critical discussions at shift turnovers indicated
that progress was being made in the area of ownership and questioning
attitude.
However, the inspectors continued to observe coordination and
communications problems which indicated the licensee still had room to
improve performance in this area.
Examples include demineralized water
system valve work, authorized as Minor Maintenance on June-16. that
resulted in a nine foot addition to the Site Drain Tank level because
multiple valves were worked at once without adequate configuration
control. A midrange radiation monitor detector (RM-A1(G)) needed repair
on June 17, resulting in entry in an Offsite Dose Calculation Manual 7-
day Limiting Condition for Operation (LCO),
However work was postponed,
and a replacement detector had to be taken from another radiation
monitor (RM-A2), and the LCO was exited with 1 minute remaining on June
24. A hydrostatic test of containment penetration modifications was
delayed because Operations did not fill and vent the system prior to
hanging the clearance as had been agreed upon in the pre-job briefing on
June 25.
c.
Conclusions
These observations caused the inspectors to conclude that Operations
ownership and communications remained a challenge to the licensee, but
licensee management was aggressively
in an effort to improve performance. pursuing the causes of the problems
The inspector assessed the licensee's performance, with respect to this
restart-related issue, in the five NRC continuing areas of concern:
Management Oversight - Good
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Engineering Effectiveness - N/A
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Knowledge of the Design Basis - N/A
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Compliance with Regulations - Adequate
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Operator Performance - Adequate
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Operations Organization and Administration
06.1 Effective June 21. M7. Charles (Chip) Pardee assumed the duties and
responsibilities of Director. Nuclear Plant Operations.
Bruce Hickle
assumed the duties and responsibilities of Restart Director.
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06.2 Effective June 11, 1997. Thomas Taylor was named Director. Nuclear
Operations Training.
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Quality Assurance in Operations
07.1 Doerability Evaluation Proaram
a.
Insoection Scope (40500)
The inspectors reviewed the licensee's 3rogram for evaluating
operability.
This included review of tie licensee's procedure, review
of recent operability determinations, and discussions with operations
personnel.
Applicable Regulatory requirements included the Technical
Specifications (TS),10 CFR 50 Appendix B. and GL 91-18. Information to
Licensees Regarding Two NRC Inspection Manual Sections On Resolution of
Degraded and Nonconforming Conditions and on Operability, dated
November 7. 1991.
b.
Observations and Findinas
The inspectors reviewed CP-150. Identifying and Processing Operability
Concerns. Revision 1. dated May 6.1996. This procedure provided
instructions for determining the operability of components required to
maintain safe operation of the plant.
The inspectars noted several
areas in which procedure guidance was limited, resulting in the
potential for implementation deficiencies in performance of operability
evaluations.
Operability evaluations were documented in operability
concern resolution (OCR) reports. There was no standard methodology
established for the implementation and tracking of compensatory actions
specified in the OCRs.
The inspectors identified no examples of OCR
compensatory actions which were not implemented.
There was no guidance
on the content, basis or reviews recuired for a Justification for
Continued Operation evaluation to adcress a degraded but operable (not
fully qualified) condition. The inspectors noted that the procedure
required appropriate management involvement in operability reviews,
which included a required review by the Plant Review Committee (PRC).
The following OCRs were reviewed to assess performance in this
area:
OCR RM-97-RM-A5(I) Radiation Monitor. RM-A5. Automatic
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Ventilation Recirculation Feature Not Installed as Described in
the FSAR. dated January 8. 1997.
OCR DP-97-DBPA-1A. Battery Load Test Profiles Not Changed by
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Modification MAR 93-05-07-01, dated March 11. 1997.
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OCR MU-97-MUP-3/A/B/C DC Backup Lube Oil Pumps for Make-
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up/ Purification Pumps Not Safety Related, dated February 10, 1997.
OCR RW-97-RWH-338, 44B, 49B Three Raw Water Hangers,
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Vertical Rods Bent / Deformed, dated May 22, 1997.
OCR EG 97-EGDG 1A/1B, Non-Safety /Non-Seismic
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Components Installed in Safety / Seismic Application,
dated January 9, 1997.
OCR RW-97-RWP-3A, Physical Location of RWP-3A Flow
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Instrument (Annubar) Does not Meet Vendor Requirements
for Minimum Run of Straight Pipe, dated June 17, 1997.
OCR DH 97-DHV-21. DHV-21 Has Portions of Valve Seat
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Ring Removed, dated January 23, 1997.
! DH-97-DHHE-1A, DHHE-1A South Support Pedestal
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.cked, dated May 5, 1997.
The inspectors' review of OCRs identified no operability
conclusions which were not adequately justified and documented.
However, the inspectors noted that the operability evaluation for
OCR DH-97-DHHE-1A was approved based on preliminary calculations
completed on May 9, 1997.
These calculations, which had not been
design verified as of July 10, 1997, were performed as part of a
Request for Engineering Assistance (REA) to evaluate operability
of a decay heat removei heat exchanger.
The requirements for
performance of REAs were specified in Administrative Instruction
(AI)-4108, Nuclear Engineering Processing of a Request for
Engineering Assistance Revision 2 dated March 27, 1997. Design
verification was not required to be performed on an REA unless
either a supervisor determines it was necessary, or the REA was to
be used for a design analysis.
The f. eat exchanger was required to
be operable in Mode 5.
Since Procedure CP-150 did not saecify the
method for performance of the operability evaluations, t7e use of
unchecked or unverified calculations was permitted by the
licensee's program. Discussions with licensee engineers disclosed
that they consided the use of the unchecked calculations to be
more or less equal to engineering judgement. The inspectors
identified the use of unchecked or unverified calculations, which
form the basis for operability determinations and the lack of
detail in Procedure CP-150, as a weakness in the licensee's
operability determination program.
c.
Conclusions
The licensee's operability procedure (CP-150) provided adequate guidance
for this activity.
However, a weakness was identified in the licensee's
operability program concerning the lack of detail in Procedure CP-150
for performance of operability evaluations, and the use of unchecked or
unverified calculations to form the basis for operability evaluations.
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The operability evaluations reviewed demonstrated that the equipment or
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system operability conclusions were adequately justified and documented,
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There was no specific self assessment surveillance or audits of this
activity, although the PRC review of OCRs provided a mechanism for
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management overview.
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The inspectors assessed the licensee's performance, relative to the
Operability Evaluation Program, in the five areas of continuing NRC
concern:
Management Oversight - Adequate
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Engineering Effectiveness - Adequate
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Knowledge of the Design Basis - Adequate
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Compliance with Regulations - Adequate
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Operator Performance - Adequate
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07.2 Reportability Proaram
(Ocen) EA 97-094 (01013. 01023). Reoeat Failure to Make Timely Reports
.tp the NRC
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a.
Insoection Scone (40500)
The inspectors reviewed the licensee's program for reporting events and
conditions to the NRC as required by 10 CFR 50.72 and 50.73.
This
included review of the licensee's procedure, review of recent
reportability determinations, and discussions with operations personnel.
b.
Observations and Findinos
The inspectors reviewed the licensee's current procedure for
implementing the reporting requirements of 10 CFR 50.72 and 50.73 CP-
151. External Reporting Requirements. Rev. 1, dated June 25, 1997.
The
inspectors noted that the procedure defined Discovery Time as follows:
"For the purposes of the reportability time clock, it is the time when
the SM or Shift Supervisor en Duty (S500) determines that a condition is
reportable." ~ This statement was not consistent with 10 CFR 50.72,
which requires that the re)ortability time clock for one-hour and four-
hour reports starts with tie occurrence of the event or condition.
It
also was not consistent with 10 CFR 50.73, which requires that the
reportability time clock for 30-day reports starts with the discovery of
the event or condition.
The ins)ectors interviewed the on-shift Nuclear
Shift Manager, who stated that tie time clock for reportability (for
one-hour, four-hour. or 30-day reports required by 10 CFR 50.72 and 10 CFR 50.73) started when the SM determines that a condition was
reportable. The SM's understanding was consistent with the procedure
but was inconsistent with the regulations.
The inspectors reviewed the licensee's response to Violation EA 97-094,
for repeat failures to report conditions as required by 10 CFR 50.72 and
50.73.
This violation was identified as an apparent violation in NRC
Inspection Report number 50-302/97-04 dated April 11, 1997.
In lieu of
attending a predecisional enforcement conference, the licensee issued a
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written response to the violation in a letter dated May 15. 1997. The
Notice of Violation was issued by tne NRC in a letter dated
June 6, 1997.
In the May 15 response, the licensee committed to improve
the reportability process per Restart issue OP-4.
Licensee Restart
Issue OP-4 included revising Procedure CP-151.
The inspectors concluded
that the definition of Discovery Time in CP-151. Rev.1. was inadequate.
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This inadequate procedure and corrective action was identified as a
Violation (VIO 50-302/97-08-01). Inadequate Corrective Action and
Procedure for External Reporting Requirements.
The inspectors noted that CP-151. External Reporting Requirements. Rev.
1, was generally well organized, detailed, and comprehensive. There
were noted improvements over the previous reporting procedure.
including:
deletion of the determination of a ' design basis issue * and
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replacing it with a 'reportability recommendation. ' This removed
a confusing and unnecessary intermediate step in the process of
determining reportability.
a new requirement for tracking the outstanding reportability
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evaluations. The inspectors verified that these were tracked by
the Nuclear Shift Manager and displayed in the Plan of the Day.
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During the inspection documented in NRC Ins)ection Report number
1
50-302/97-07, the inspectors had reviewed t1ree licensee reportability
!
f
evaluations and concluded that all three were of poor quality,
indicating a weakness in the licensee's resortability evaluation
program.
During the current inspection, t7e inspectors selected six
Suspected Reportable / Design Basis Issues for review.
The issues were
identified on Precursor Cards during January through May 1997. The
inspectors found that all six of the reportability reviews were r.ot
completed as of the time of this inspection.
All had received time
extensions from the NuJ. ear Shift Manager, as allowed by the licensee's
process. The inspectors concluded that the licensee was not always able
to make prompt reportability determinations.
Also, the licensee was
still in the process of implementing corrective actions for viol 6 tion EA
9/-094 and in addition addressing the weakness in the reportability
evaluation program that was identified in Inspection Report (IR) 50-
302/97-07.
c.
Conclusions
The inspectors identified a violation for an inadequate procedure and
corrective action for reportir.g.
Licensee Procedure CP-151. External
Reporting Requirements. Rev. 1. dated June 25, 1997, stated incorrectly
that the reportability time clock (i .e. , for one-hour, four-hour. and
30-day repor ts) starts when the Nuclear Shift Manager determines that a
condition is reportable.
This statement did not adequately implement
the reporting requirements of 10 CFR 50.72 and 10 CFR 50.73.
The inspectors assessed the licensee's performance, relative to the
_
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9
Reportability Program, in the five areas of continuing NRC concern:
ManagementOversight-Inadequate
.
Engineering Effectiveness - h/A
.
Knowledge of the Design Basis - N/A
.
Compliance with Regulations - Inadequate
.
Operator Performance - N/A
f
.
07.3 Licensee Self-Assessment Activities
a.
Inspection Scooe (71707. 40500)
lhe inspectors reviewed various licensee self-assessment activities and
corrective action process which included:
Routine reviews of Nuclear Quality Assessments (NOA) activities
.
and surveillance report findings:
Observation of the NQA monthly audit 97-06 exit interview and
review of the 97-05 report:
Reviews of precursor cards entered in to the corrective action
.
system:
Observation of management Corrective Action Review Board (CARB)
meetings:
Notable observations are discussed below.
b.
@ervations and Findint1s
The inspectors observed that the level and detail of CARB reviews of
significant Level A and B PCs has gotten significantly better.
PC
presenters were challenged to justify their conclusions and the adequacy
of their corrective action plans.
Emphasis was placed on ensuring
corrective actions were effective, long-term solutions to problems and
ensuring all root causes had corresponding corrective actions.
These
items had not consistently been enforced in the past by the CARB as
expectations evolved for the role of CARB which was only initiated in
January of 1997.
The inspector observed that several new members of the
licensee's management team were also new members of CARB and many of
the observed improvements could be attributed to them applying their
personal standards to CARB reviews,
c.
Conclusions
The inspectors concluded the licensee self-assessment activities were
effective and specifically that the CARB had a definite. positive impact
on quality of corrective action plans. The inspector considered this
the result of the impact of the new CARB members.
The inspector assessed the licensee's performance, with respect to this
.
_
10
restart-related issue, in the five NRC continuing areas of concern:
Management Oversight
- Good
.
Engineering Effectiveness
- N/A
.
Knowledge of the Design Basis - N/A
.
i
Compliance with Regulations
- Good
.
Operator Performance
- N/A
.
08
Miscellaneous Operations Issues
08.1 fClosed) Restart Item to Verify License Conditions are Met (FPC Restart
- tem R-15)
a.
Insoection Scone (92901)
This item was added to the NRC restart list due to concerns that the
licensee had not fully implemented all of the License Conditions. The
licer. a completed their license condition verification per Item R 15 on
their restart list. The inspector reviewed the results of that
investigation and independently verified selected. conclusions and the
licensee's compliance with the current license conditions in Operating
License DPR-72, through Amendment Number 155 Section 2.C.
b.
Observations and Findinas
The ins]ector's review encompassed the 10 license conditions, numbered
2.C.1 tirough 10, each of which had several subparts.
The licensee's
review encompassed all parts of the License Conditions, but the
inspector's review was only of the specific amended conditions in
Section 2.C. because the remainder of the license was essentially
standard terminology.
Condition 2.C.4 was no longer applicable, since
it was deleted in Amendment 20 in 1979.
The licensee's review verified
that documentation existed to substantiate compliance with each license
condition, but they determined that three conditions were not met and
generated corrective action system PCs 97-0990, 2727, and 1527 to
implement cor rective action.
The three conditions were 2.C.(2)b. f. and
h. which were specific directions to perform surveillance requirements
(SR) at a nore restrictive periodicity for one time following Improved
Technical Specification (ITS) implementation via Amendment 149 on March
12, 1994. The licensee determined these more restrictive requirements
had not been met although each of the SRs was done within the required
Ils periodicity. They documented the noncompliances in a letter to the
NRC dated May 20, 1997. The inspector identified a fourth condition.
2.C.(2)e. similar to the others that also had not been implemented but
was also within the required TS periodicity. The licensee's
'
investigation revealed that they had provided the more restrictive
license conditions as part of their Amendment 149 submittal to implement
the ITS but the staff lad not addressed them in the Safety Evaluation
Report for the amendment and the licensee had not tracked them to ensure
completion. The licensee's letter, dated May 20. 1997, committed to
implement a change for dispositioning license correspondence form the
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. - -
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11
NRC. The inspector verified this change was progressing and would
result in formalized Nuclear Licensing procedural guidance. The
inspector also observed the licensee had made numerous other changes in
processes and personnel in order to preclude a similar problem from
recurring.
Neither the inspector nor the licensee could find any documentation to
determine the basis for the more restrictive license condition
,
requirements for the named SRs.
Some of the conditions were not
attainable such as 2.C.(2)e, which required SR 3.6.1.2 for the
Containment Tendon Surveillance Program to be "successfully demonstrated
'
3rior to entering MODE 2 on the first plant start-up following Refuel
Outage 9."
This SR was completed on January 4, 1994 with the full
awareness of the staff and per the TS Jeriodicity but it did not meet
the licensee condition to be done on tie first start-up following Refuel
>
Outage (RF) 9 because RF9 ran from April 7 to May 29. 1994. The tendon-
surveillance would not normally be expected to be done on a start-up
-
following an outage.
The inspector determined the safety significance
of these four noncompliances was minor. Consequently, this failure to
implement the license condition constitutes a violation of minor
significance and in accordance with Section IV of. the NRC Enforcement
.
Policy, is being treated as a Non-Cited Violation (NCV 50-302/97-08-02).
[
Failure To Implement License Condition Surveillance Requirements
Associated with Improved Technical Specification Implementation.
The inspector also reviewed NRC Information-Notice 97-43. License
Condition Compliance, which discussed several specific license condition
4
non-compliances and recommended licensees review their license
conditions.
The inspector verified that none of the s)ecific examples
.
were relevart to the licensee and concluded that they lad effectively
implemented the recommendation to review the licenses conditions by this
!
restart item review.
License Condition 2.C.5 for boron dilution flow indicators was also a
potential noncompliance because the flow indicators were not capable of
meeting the accuracy requirement to indicate 40 gpm flow.
The licensee
-had not addressed this noncompliance in the May 20 letter, nor had they
addressed it in'a Licensee Amendment Request to the staff dated June 26.
1997 requesting deletion of the flow indicator requirement because the
flow indicators were no longer utilized in the boron precipitation
mitigation strategy.
The inspector's review of this noncompliance is
continuing and will'be dispositioned in a subsequent report.
The inspector identified several other discrepancies during this review.
,
The May 20 letter to the NRC contained erroneous information regarding
,
-the completion date and plant mode for condition 2.C.(2)b. The
consequence was negligible and did not affect the licensee's conclusion
that the SR was accomplished when required by TS but it indicated poor
attention to verification of licensing correspondence.
.
The inspector also observed that the three PCs opened for the licensee-
i
identified noncompliances in April of 1997, were all graded Level C
_
_
_ _ _ - _ - _ _
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_ _ _ ___ - _ _ _ .
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12
requiring an apparent cause evaluat1on.
One PC remained open with no
<
apparent cause done. The second was cicsed without any corrective
!
actions identified and a weak apparent cause, statin
communications practices would preclude recurrence. g current Licensing
'
The third was
closed by an apparent cause stating the SR was done when recuired by TS,
i
and the PC never should have been initiated,
it did not adcress the
'
failure to implement the license condition and was closed by the
f
administrators of the corrective action system without noticing the
omission and inadequate closure justification. The inspector identified
that the committed corrective action in the May 20 letter to formalize
the Licensing process was not contained in any of these three PCs which
was an example of corrective actions being taken outside of the
corrective action system. The inspectors verified that the licensee has
appropriately initiated corrective actions for these problems.
The inspectors identified several problems with the licensee's closure
packages for this and other items. The format of the packages was
i
inconsistent; the restart item action plan completion was difficult to
verify because it was not u) dated with closure information, and packages
were occasionally missing o)jective evidence of corrective action
completion. Signatures were missing various forms, and restart items
were closed without the associated PCs and corrective actions being
closed, indicating a lack of attention to detail and poor closure.
Restart items were also closed without the extent of condition for a
problem being determined and reviewed. The inspectors discussed the
inability to close items until the extent of condition and corrective
actions are complete with the licensee. The licensee group responsible
for the packages had conducted training to address many of these
problems prior to the above observations but after the assembling of the
reviewed packages so future closure packages should be improved,
c.
Conclusions
The inspector determined the licensee comoleted the restart item
requirement to review the license conditions so the open item is closed.
However, several noncompliances were identified that indicated poor
tracking of regulatory requirements in the past.
Also, several
deficiencies were identified indicating poor attention to verification
of licensing correspondence, poor use of the corrective action system,
and weak expectations for the closure of restart items.
The inspector assessed the licensee's performance, with respect to this
restart-related issue, in the five NRC continuing areas of concern:
Management Oversight - Adequate
Engineering Effectiveness - N/A
.
Knowledge of the Design Basis - N/A
.
Compliance with Regulations - Inadequate
.
Operator Performance - Adequate
.
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13
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a.
Insoection Scone (62707. 61726)
Using Inspection Procedures 62707 and 61726 the inspectors observed all
or portions of the following work requests (WR) and Surveillance
Procedures (SPs) and reviewed associated documentation.
The following
activities were included:
. SP-110A
"A" Channel Reactor Protectior, System Functional
Testing
. SP-112
Calibration of the Reactor Protection System
. SP-354A
Monthly Functional Testing of the Emergency Diesel
Generator (EGDG)-1A
. SP-335C
Radiation Monitoring Instrumentation Functional Test
of RM-Al
. WR NU 0338614
Perform alignment and recouple building spray pump
(BSP)-1B
. WR NU 0342922
Install supports and tube up air to makeup valve
(MUV)-541
b.
Observations and Findinas
During the observations of impeller replacement on BSP-1B. per WR NU
03338614 the inspector observed the preparation and installation of the
component.
The licensee began performing the maintenance activity in
the decay heat room, but preparation for a reactor building bus outage
removed AC power to the ou'lets in the room.
This power supply was
necessary for the magnetic tsearing heater planned to be used to heat the
coupling to allow installation on the pump shaft.
This lack of power
delayed this portion of the task.
When power was restored, the maintenance technicians discovered that the
coupling and shaft would not fit in the required tolerances.
Even
though both components were within design specifications, they were at
the extreme, o)posite ends of the tolerance band and would not make a
proaer fit. T7e licensee ordered a new coupling from the manufacturer
wit 1 a measurement which would allow a proper fit to the shaft.
Completion of reinstallation of the pump impeller continued after this
inspection period and will be discussed in a future inspection report.
The inspector observed preparations for the performance of SP-110A, "A"
.
1
.
14
-Channel Reactor Protection System function Testing. Revision 4.
The
I
technicians reviewed the procedure and assured that all equipment
necessary to perform the surveillance was available and in calibration.
The technicians notified the 5S00 that they were ready to begin the
)rocedure. The SS00 required the technicians to verify that no
Emergency Feedwater Initiation and Control (EFIC) channel trip was in
f
place, as recuired by section 3.5. Limits and Precautions of the
procedure, khen the technicians ins
discovered that a trip was in place.pected the EFIC panels, theyInvestigations revea
trip had been in place for over two weeks, as part of the EFW cavitating
venturi functional test procedure, which was still cpen awaiting a
determination by engineering on whether to continue the testing.
l
Both of these tasks were planned and scheduled when other tasks which
would interfere with their performance were occurring. No regulatory
requirements were violated in these occurrences, but the lack of good
'
coordination and review of existing conditions prior to scheduling a
task demonstrates a weakness in the planning and scheduling process,
c.
Conclusions
'
Maintenance activities were generally completed in an acceptable manner.
Some weaknesses were observed in coordination of maintenance activities,
which had a negative impact on the completion of certain tasks.
M1.2 Maintenance Backloos
a.
Insoection Scoce (62700)
As part of inspection of the licensee's maintenance activities, the
inspectors reviewed the control of Corrective Maintenance (CM) and-
Preventive Maintenance (PM) backlogs,
b.
Observations and Findinos
The CM backlog has been relatively high (700+ open WRs) for some period
of time.
Based on discussions with licensee personnel and review of
performance trend charts, work-off curves have been generated to reduce
the CM backlog to below 200 Maintenance Requests (MRs) by September
1997. However, because of increased maintenance requirements resulting
from the System Readiness Reviews and backlog reviews, the issue of new
CM WRs has about equaled the number of WRs closed. Therefore, the
backlog has remained over 700 through April and May 1997.
Licensee
management stated that the System Readiness Reviews should be completed
in July, and'the continued emphasis on the CM backlog should start to
show results.
To ensure that their CM backlog was reduced to less than
200 by September 1997, specific initiatives had been implemented to
place additional emphasis on backlog reduction. These initiatives
included: more focus on schedule (adjusting manpower loading, evaluating
restraints, etc.), an increase in resources for the maintenance process
.
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.
15
'(Maintenance and Operations), streamlining the work control process. and
continuously.looking at indicators and performance to adjust schedules.
The backlog of PMs was tracked by equipment tag number. The number of
,
tags past their due date and the number of tags more than 25% past their
due date (past their grace period) v:ere being trended. As a result of
!
increased emphasis on reducing the PM backlog, the PM backlog had been
.-
significantly reduced over the last few months. At the beginning of-
1997, the number of tags past due was over 1040 and the number more than
25% past their due date was 197. At the time of this inspection (mid
June), the number of overdue tags had been reduced to approximately 275
i
!
'and the number of tags more than 25% past due had been reduced to 55.
Thirty-three of the 55 were routine preventive maintenance WRs
i
-(greasing, adjustments, etc.), and 22 were instrument calibrations.
Most of these calibrations had some restraint. (i.e., plant condition or
4
engineering hold), preventing their completion.
The problem with
instrument calibrations not being performed within their grace period
-
was documented in NRC Inspection Report No. 50-302/97-01. VIO 50-302/97-
01-04. Failure to Perform Technical Specification Surveillance for Spent
Fuel Pool Level.
Additional problems with past due calibrations were
found in the current inspection as detailed in paragraph M1.5 below,
c.
Conclusions
The reduction of both the CM and PM backlogs was being aggressively
Jursued by licensee management. The CM backlog was still relatively
ligh, but initiatives had been implemented to reduce significantly the
backlog by September 1997. Actions to reduce to the PM backlog had
resulted in significant reductions. However, there were still 55
equipment. tag calibrations greater than 25% past their due date. The
licensee planned to reduce this number to below 20 by Sectember 1997.
M1.3 Repair of Main Steam Isolation Valves (MSIVs)
a.
Insnection Scoce (62700)
'The licensee was in the process of complete refurbishment
(repair / replacement) of the internals and inside surface of valve bodies
for all four MSIVs. The work was being accomplished by a contractor.
Welding Services. Inc., with management by the Licensee.
The inspectors
observed in-process maintenance activities for this work. The
applicable Code for this work was the USA Standard Code for Pressure
Piping -1967 Edition.
b.
Observations and Findinas
The inspectors observed the following activities and verified compliance
with the above Code and licensee _ procedures and work control documents
for the following MSIVs:
_ _ _ _ _ _ _ _ _ _ . _ _ _ - _ .
_______ - _ - _
'
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1
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.
16
MSV-411
Measuring and mapping of valve body internal surfaces to
-
determine need for repair
Machining bonnet-to body gasket seating surface and Stellite
-
seat
Weld repair to main disk surfaces
-
i
1
y
MSV-413
Machining upper body bore after weld repair
-
Post weld heat treatment (PWHT), including review of final
-
temperature strip chart, for repair to main disk
Magnetic 3 article (MT) inspection of the final machined body
-
bore and Jonnet-to-body gasket seating surface
Liquid penetrant (PT) inspection of Stellite hardfacing on
-
main disk inner seal
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- Setup for machining oversize stud holes in valve body
For the above observed work, in addition to review of work Traveler
i
30070. Main Steam Isolation Valve Disassembly. Inspection. Repair and
!
Re-Assembly. Revision 1. and the associated WRs. Weld Travelers, and
l
Inspection Plans, the inspectors verified:
)
Compliance with Welding Procedure Specifications
.
Welder qualification (including continuity records) for four
.
welders
Welding material certification for three heats of welding material
.
Certification for one nondestructive examination (NDE) Examiner
.
Calibration records for a samale of Measuring and Test Equipment
.
(M&TE) used for the above wor (
c.
Conclusions
For repair work on the MSIVs. performance was considered good.
The
contractor was doing quality work in accordance with code and procedure
requirements. The licensee appeared to be doing a good job of
management of the work.
M1.4 Measurino and Test Eouioment (M&TE)
a.
Inspection Scone (62700)
Since 1995, the licensee has identified recurring problems with control
of M&TE.
During the current inspection, the inspectors reviewed
licensee corrective actions for these pr;olems to determine if
corrective actions have been effective.
b.
Observations and Findinas
The following licensee documents, which identified problems with M&TE.
were reviewed by the inspectors:
_
.
1
.
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17
Quality Assurance (0A) Surveillance 95-0083.
Problem Report (PR) 95-0153.
.
PR 96-0349, and
.
PR 96-0395.
.
The problems identified were primarily associated with issae and return
of calibrated equipment and with programmatic deficiencies associated
with return of equipment in a timely manner.
Based on review ';f the
above documents and discussions with responsible M&TE and 0A personnel,
there appeared to have been a lack of Jnderstanding within the various
departments relative to:
(1) the need to return M&TE before its
calibration due date: and (2) the significance of lost M&TE. The
primary corrective actions included:
modification of the computer program used to track and report
.
problems with M&TE. including the ability to generate reports and
automatically generate letters when equipment was not returned
before its calibration expires:
enhancement of the process for escalating notification to
+
supervision and management when equipment was not returned before
its calibration expires: and
increased emphasis at all levels on the significant action
required to re-construct the usage history for lost M&TE.
Based on a review of a sample of current M&TE records (including records
of re-called equipment), review of recent GA audits in the arca of M&TE.
verification of control of M&TE for a sample of M&TE being used for
maintenance activities (see paragraph M1.3 above), and discussions with
responsible M&TE personnel and 0A personnel, the inspectors concluded
that corrective actions had been effective.
For the sample of records
reviewed, re-called equipment was returned on time.
c.
Conclusions
The inspectors concluded that good corrective actions were taken for the
previously identified measuring and test equipment (M&TE) problems.
M1.5
Instrument Calibrations
a.
Insoection Scoce (62700)
To verify compliance with applicable NRC and licensee requirements for
calibration of instruments, the inspectors observed the in-process
instrument calibrations detailed in paragraph b. below.
b.
Observations and Findinas
1)
Portions of the periodic calibration of Auxiliary Building Sump
1
Level Switch WD-132-LS were observed. The calibration was
performed in accordance with WR NU 0338152 and the associated
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18
Calibration Data Sheet. The calibration was performed in a
quality manner by qualified personnel in accordance with
,
l
procedures.
l
!
2)
Preparations for calibration of Fire Service System Pressure
Switches FS 41 PS (low lube oil pressure alarm for Fire Service
,.
Pump FS 2B) and FS 43 PS (auto starts FS-2B pump on low header
pressure) was started June 19, 1997, in accordance with WR NU
0316120.
During tag out of the system. Operations decided to
delay the calibration until August 1997, when mechanical
maintenance for the system was also scheduled, and needed parts
were not available. The inspectors questioned whether this delay
1
would push the calibration of the switches outside their
i
calibration due date.
i
After further review. it was determined that Switches FS 41 PS and
FS-43-PS were not calibrated on their last due date of October 30.
-
1990.
Therefore the calibrations were approximately seven years
past due. The switches were part of multi-tag PM, WR NU 0271089
,
i
initiated July 14, 1990. Calibration was com)leted for all
instruments on the WR except Switches FS-41-)S and FS 43 PS, and
the WR was closed on December 17, 1993. On that date, corrective
maintenance WR NU 0316120 was initiated to calibrate Switches FS-
41 PS and FS 43 PS. However, this WR was never performed.
it
appears this problem was caused by placing the calibrations on a
corrective maintenance WR in lieu of a PM WR, thus losing the
mechanism to track the due date.
The licensee immediately issued PC 97 3297 to determine the
implications of this problem and the necessary corrective actions.
The inspectors noted that a previous violation VIO 50 302/97 01-
04. Failure to Perform Technical Specification Surveillance for
Spent Fuel Pool Level, for instrument calibrations not being
performed Within their allowable calibration intervals, had been
issued. As part of corrective actions for Violation 50-302/97-01-
04, the licensee was in the process of revising Procedure Al 605
to provide better guidance for justifying exceeding calibration
intervals, actions required when instruments exceed calibration
intervals, and providing status reports to the S500 to identify
instruments that have exceeded their calibration interval.
In
accordance with licensee letter of response to the NRC. dated June
16, 1997, the
until June 30, procedure revision was not scheduled to be completed
1997. The inspectors pointed out that the problem
with the Fire Service pressure switches being past their
calibration due date identified another avenue by which current
practices allowed instruments to exceed their calibration
intervals. (i.e., using a corrective maintenance WR to perform
PMs.) The inspectors further pointed out that the corrective
actions in process for Violation 50-302/97-01-04 should:
(1) determine the extent of the condition: (i.e. Other cases where
use of a corrective maintenance WR in lieu of a PM WR may have
allowed an instrument to exceed its calibration interval): (2)
_ _ _ _ _ _ _ _ _ - _ _
1
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19
identify if there were other unre:.ognized avenues that would allow
instruments to exceed their calibration intervals: and (3) ensure
that planned revisions to Procedure Al 605 correct all identified
avenues whereby an instrument can exceed its calibration interval.
Corrective actions for this additional example of Violation 50-
303/97 01-04 will be reviewed after the licensee completes
f
corrective actions for the violation.
c.
Conclusions
NRC Inspection Report 50 302/97-01 identified problems with instruments
exceeding their calibration intervals. During the current inspection,
inspectors identified additional examples of instruments exceeding their
calibration intervals indicating continuing problems in the PM program.
1
(
M1.6 Once Throuah Steam Generator Insoections
a.
Insoection Stone (50002)
The inspector reviewed procedures and plans for inspection of the OTSGs.
and observed eddy current (ET) inspection and analysis activities.
b.
Observations and Findinas
At the time of the inspection the licensee was conducting ET
examinations in both OTSGs.
The examination and analysis crews were
working two 12-hour shifts in order to complete the examinations as
scheduled.
The inspector reviewed the following OTSG inspection documents:
Surveillance Procedure. SP-305. OTSG Inservice Inspection.
Revision 21. Effective Date - June 10. 1997, and
Steam Generator Eddy Current inspection Guidelines (OTSG ET
.
Guidelines) Revision 0. Effective Date - June 10. 1997.
SP-305 was the licensee procedure that provided administrative and
technical guidance for determining the operability of each OTSG with
respect to the plant Technical Specifications.
provided the technical direction for ET analysts performing data
acquisition and analysis.
The inspector reviewed data from completed ET inspections and observed
the activities of resolution analysts (day and night-shift crews)
working at the site.
The inspector also participated in a conference
call between the licensee and NRR to discuss the status and findings of
_
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20
c.
Conclusions
The licensee's steam generator examination program appeared to be well
planned and well managed.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Reactor Buildina (RB) Coatin.g1
a.
Inspection Stone (62700)
1
The inspector reviewed 3rocedures and documentation. and observed work
activities involved wit 1 the removal and replacement of protective
b.
Observations and Findinas
l
The inspector conducted a walk-through inspection of the RB to observe
work and work activities.
Coating removal and replacement activities
fu the liner plate have been on hold since the inspector's last tour.
(the week of May 19. 1997.) pending resolution of. concerns about
inspections required by the " Containment Rule." and discovery of
degradation of the liner plate adjacent to the concrete on the 95 fcot
level.
(The condition of the corrosion-damaged RB liner plate was added
to the licensee's restart list during the week of June 16-19. 1997.)
Cleaning of grime and oil residue off of the liner plate paint, in areas
not affected by the hold have shown that a good portion of the liner
plate coating system was in relatively good shape.
The licensee had issued the following "Special Process Specifications"
for the inspection of the RB liner plate and penetrations:
SPS VT N17. Visual Examination of ASME Section XI. Subsection M
Components. Rev. 0, dated May 30. 1997, and
SPS VA-N18. Visual Examination Criteria of ASME Section XI.
.
Subsection IWE Components. Rev. O. dated May 30. 1997.
Visual inspectors had been trained and certified in the use of the new
examination procedure, SPS VT-N17 and the inspector observed the
initial examinations of the corrosion damaged liner plate on the 95-foot
level of the RB. As provided by the procedure, the licensee's visual
inspectors were using a digital camera to record questionable
indications for future evaluations.
The inspector neted that activities had continued in the removal and
replacement of damaged coatings on concrete structures, floors, and
miscellaneous steel.
The inspector noted that considerable progress had
been made on the removal and replacement of coatings cn the floors and
concrete structures,
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The inspector reviewed the following precursor cards involving
protective coatings inside the RB:
Precursor Card /Date
Title /Subiect
97-2843 dated April 28, 1997
Journeyman Painter added extra thinner
to the floor sealer being applied to
c
the 160' elevation.
97 3163 dated May 12, 1997
Problems identified during
surveillance of procedure compliance
by RB painting crew.
97 3233 dated May 8, 1997
Findings of self-assessment of RB
coating activities.
1
97 3256 dated May 13, 1997
Self-assessment revealed that buckets
1
used to transport paint into RB may
require identification with P I./ Batch
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Numbers.
97-3391 dated May 17, 1997
Environmental readings were not taken
in the areas being painted on May 15,
1997.
The inspector noted that these precursor cards were initiated as the
result of questioning by personnel involved with the painting
activities.
In two of the cases (PC Nos. 97-2843 and 97-3391). work was
stopped and the affected coating materials were removed and replaced,
c.
Conclusions
. The addition of the RB liner plate condition to the-licensee's restart
list was an indication that management ap) eared to be more directly-
Involved with the problems associated wit 1 the repair and replacement of
Reactor Building coating systems.
M2.2 Maintenance Paintina Practices
a.
Insoection Scone (62707)
During the observations of the installation of the Cuilding Spray Pump
-(BSP) IB rotating assembly, the inspectors noted that the maintenance
technicians were cleaning paint from the studs and nuts used to
reassemble the puma.
The inspectors questioned the aractice of painting
the fasteners on t1e safety related pumps, both the 3SP and other safety
related pumas located throughout the plant. -The licensee informed the
ins)ector tlat the painting was used for corrosion control.in certain
hig1 humidity-locations, such as the decay heat rooms where the BSPs
are located,
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Observations and Findinas
The inspector reviewed licensee Procedure MP-139. Application of
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Protective Coatings Outside of Reactor Building. Revision 27. This
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procedure is used to control painting throughout the plant, exclt' ding
>ainting inside of the Reactor Building.
Step 3.2.19 of Limits and
3recautions, stated that if Jainting machinery or equipment, the
was to ensure that any vent 1 oles, drain holes, moving surfaces, painter
I
valve
stems, etc. were to be protected during the painting process and were
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not painted. Step 4.4.4. Application of Protective Coatings. stated
that when painting plant equipment (motors, valves, etc.), the painter
was to ensure that all surfaces that should not be coated were
protected.
The procedure li,ted valve packing. tags, sliding surfaces,
vent holes, etc. as examples of surfaces to be protected during the
coating applications.
Enclosure 1. Application Check List to the
procedure, listed as a special consideration ft.c coating plant
equipment, including valves, motors, and MOVs. that measures be taken to
ensure threads. moving parts, packing, vent / weep holes, name plates,
i
etc. were not painted.
,
The inspector identified a concern about control of painting activities
to the licensee management.
The potential existed. if the control of
the process was lost, to paint some component in such a manner as to
hinder its ability to perform its function, or in the case of a threaded
component, to prevent ready access to allow maintenance activities. The
licensee generated a precursor card. 97-4801, to address reassessing the
existing program for effectiveness and assuring that the process is
properly controlled,
c.
Conclusions
The controls for painting outside of the reactor building, while
existing in licensee procedures, wore inconsistently applied. The
-licensee instituted a review process to assess and upgrade the control
program.
M3
Maintenance Procedures and Documentation
M3.1 Reactor Protection System Channel Trin
a.
Insoection Scone (62707)
The inspector reviewed the channel trip received on the reactor
3rotection system during performance of SP-112. Calibration of the
Reactor Protection System. Revision 56.
b.
Observations and Findiegg
On July 7. -1997, during the performance of SP-112. an unexpected trip
occurred on reactor protection system channel. While performing the
calibration on the T
module. the procedure directed the technician to
y
obtain the module serial number. This requires that the module be
removed from the Reactor Protection System (RPS) panel. The technician
informed the cci 'rol room operators that he would be removing the
module. The op ators questioned the technician as to the impact of
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removing the module.
The technician informed the inspector that he
speculated that since the module was already down scale, no alarms would
be received. The operators failed to assure that the technician was
certain of the Outcome of removing the module.
When the module was
removed, a trip of the channel was received.
During the operating
condition Mode 5. that the )lant was in during this event. the RPS trip
.-
was not required to be opera)le.
A review of the procedure revealed that it did not include any alarms or
trips that would be received as a result of removing the modules to
perform the calibration.
This procedure was normally performed during
refueling outages in Modes 3. 4, 5. or 6 but one procedure allowed
)erformance in Modes 1 and 2.
The reliance on the technician's
(nowledge and memory for the im)act of the performance of the procedure
created the opportunity for pro)lems to occur.
The lack of guidance in
!
the procedure for alarms, actuations, and potential problems that might
be encountered during the performance was a weakness.
c.
Conclusions
The control room operator's acceptance of speculation of the impact of
removing a module from the RPS panel and not requiring that the
technician verify his supposition displayed a lack of questioning
attitude.
The fact that the
warning of potential alarms, procedure did not provide the information
actuations, problems, etc., even though
this procedure was routinely used to satisfy technical specification
surveillance requirements, demonstrated a weakness in procedural
controls.
M3.2 Surveillance Schedulina Practices
a.
Insnection Scone (62707)
The inspector reviewed the licensee's process for controlling the
completion of technical specification surveillance requirements,
b,
Observations and Findinas
The inspector reviewed licensee Procedure SP-443. Mester Surveillance
Plan Revision 108. The purpose of the procedure was to provide a d ua
base of surveillance requirements and the necessary interpretation of
those requirements into specific surveillance plans for each plant staff
section.
SP-443 was considered to be a scheduling and tracking document
for assuring and verifying that surveillances were scheduled and
performed when due.
Step 3.2.1. Description, stated that the procedure specifically provides
schedule requirements for all surveillances capable of calendar
scheduling.
This procedure specified the responsibility for
performance surveillance frequency and interval, nominal due date, and
applicable modes for performance.
During the review the inspector
noted that the procedure required that the performer shall check the
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previous surveillance test interval and determine the maximum previous
surveillance test interval and determine the maximum time permitted to
delay performing a surveillance without exceeding the TS test interval
requirements of Section 3.6.2.
The inspector noted that the correct
reference was TS 3.0.2 and notified the licensee of the error.
.-
Reviewing the SP-443 schedule for June 25. 1997. SP-9078. Monthly
Functional Test of 4160V ES Bus "B" Undervoltage and Degraded Grid
Relaying, and SP-354B. Monthly Functional Test of the Emergency Diesel
Generator EGDG 18. the ins)ector noted that both were scheduled to be
completed on that date.
T1e previous performance of these surveillances
had been on May 23, 1997.
However, the surveillance was not performed,
as it was not included on the work schedule.
The SSOD informed the
inspector that when a conflict existed between the work schedule, which
was not procedurally controlled, and the SP-443 schedule, the work
schedule took precedence and was followed.
The ability of an
uncontrolled process superseding a controlled process used to assure
that TS surveillance requirements were met created the possibility that
a surveillance may inadvertently be precluded from the work schedule and
be missed.
The inspector reviewed a recent Quality Programs surveillance (OPS) and
observed that a weakness was discovered in the SP-443 scheduling
process. SP-443 schedules surveillances on given days of the week, for
example a thirty day surveillance being scheduled the third Thursday of
every month.
This did not exactly correspond to a monthly schedule.
Several months of the year the surveillances are being routinely
scheduled for performance in the grace period allowed by TS 3.0.2.
The licensee has noted the identified weaknesses by Ouality Programs and
the issues identified in this inspection.
Steps are being taken to
procure new scheduling software, capable of addressing the OPS and NRC
identified concerns.
c,
.C.onclusions
The lack of coordination between the work schedule and the SP-443
schedule created a possible avenue for missing TS required
surveillances. Surveillance scheduling practices at the site have
demonstrated weaknesses, identified both by the NRC and the licensee.
M3.3 Adherence to Maintenance Procedures and Limitations of the Procedure
Chance Process
.The inspectors have noted that several maintenance problems have been
identified by the licensee and t'.eir Quality Assurance (0A) auditors
that are indicative of failure to follow procedures. A common theme in
the causes of these problems was maintenance personnel working around
procedure problems versus addressing them. The inspectors viewed this
as linked to the perceived difficulty amongst the licensee's staff at
processing procedure changes.
The licensee recently issued a change to
their procedure change process contained in Administrative Instruction
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400. New Procedures and Procedure Change Process. Revision 21 which
!
simplified the prccess for non-intent changes. The licensee expected
i
the screening out of the full safety evaluation process for these type
of changes should allow a change to be processed in approximately two
I
weeks versus the previous norm of four weeks. The inspectors did not
l
identify any problems with this revision.
The inspectors also noted a OA report identified a lack of control of
the licensee's NUPOST process which is a computerized tracking system
for procedure comments to be incorporated in a subsequent revision.
The
report identified that there was not any requirement to use the NUPOST
system or respond to the postings and that the use of NUPOST varied by
site department.
The inspectors have observed similar inconsistencies
j
and inadequate disposition of NUPOST comments. Another problem the
i
inspectors observed and determined through interviews with licensee
personnel was that it was difficult to determine the scope of changes
and revisions to field copies of procedures,
ihe licensee did not-
routinely distribute a revision history or list of effective pages in
the controlled field copies of-procedures.
Consequently, when a
revision was issued. it was difficult to determine the scope or reason
for the change and which portions of the procedure were affected. While
the scope change information was avc11able from Document Control and the
affected Jages could be determined from checking individual pages for
revision Jars, the inspector concluded the licensee's process was not
fully supportive of the procedure end users.
c.
Conclusions
The inspectors concluded that there was still room for improvement in
the licensee's procedure change process as well as control of the NUPOST
system. The licensee was evaluating their process to make it more
efficient and a better aid to the plant staff.
H6
Maintenance Organization and Administration
M6.1 Effective June 2.1997 Mark Schiavoni became the new Assistant Plant
Director. Maintenance, assuming the duties and responsibilities of this
position on June 26, 1997.
H8
Miscellaneous Maintenance Issues
M8.1 Cavitatino Venturi Functional Test TP#3
a.
Insnection Scope (62707)
The inspector continued to review and observe the post modification
functional test for installation of the emergency feedwater system
cavitating venturies,
b.
Observations and Findinos
The inspector reviewed licensee procedure. Modification Approval Record
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(MAR) 9610-02-01 TP# 3. Simultaneous Operation of EFW A train and B-
train. Revision 0.
This procedure detailed the third and final test of
the EFW cavitating venturi modification, which was running both trains
j
simultaneously to verify adequate performance of the venturies, assure
adequate Net Positive Suction Head (NPSH) was available for both pumps
at muimum flow conditions, and to verify whether the EFIC flow limiting
.-
logic will function in conjunction with the cavitating venturies.
On June 19, 1997, the licensee completed all prerequisites and began the
test. The test started both EFW pumps. After a short duration run.
EFP-2, the turbine driven emergency feedwater pump, began to lose speed.
The pump was secured and an investigation was conducted.
It was
discovered that the auxiliary steam supply, from adjacent fossil units,
was coming through a small bypass line and not the normal sunly valves.
This smaller line did not provide enough steam to maintain E:A2 at full
speed. The aum) was reset, and the main su
The test
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resumed. witi E P-2 performing as expected.pply valves opened.
A portion of the test was designed to measure th? line loss in the
suction flow path.
If the measured pressure drop did not exceed 3 psig.
the licensee planned to simulate a level of approximately zero inches in
the emergency feedwater tank by throttling closed the suction valve from
the tank and testing for adequate NPSH to the pumps.
The measured line
losses were approximately 3.8 psig. The licensee issued a test
exception report and did not perform the NPSH tests with the throttled
valve.
This was in adherence with step 7.3.5 of TP# 3.
Valve stroking tests were completed, as part of this test, with all
valves performing as required. Tne licensee verified that the
cavitating venturies performed as designed, simulating a faulted OTSG.
with botii pumps running.
Following the com)1etion of this portion of
the test, an instrument line coupling on EFL1 motor driven emergency
feedwater pump venturi
failed.
The licensee stopped the subsequent
emergency feedwater leak by tripping EFP-1 and closing the recirculation
isolation valve. EFV-24. and the suction valve. EFV-3.
After the leak was isolated, the inspector witnessed the licensee
satisfactorily complete Motor Operated Valve Analysis and Test System
(M0 VATS) testing on EFV-12 p'r WR NU 0340313,
The remainder of TP# 3
was postponed until after r 4 airs had been completed on the instrument
line and the licensee had inspected the other test connections to ensure
that those connections were intact.
On June 20. 1997, the licensee resumed testing the response of the
cavitating venturies in conjunction with the LFIC system flow bias in
bypass and with the EFIC system flow bias in normal. Testing with the
flow bias in bypass resulted in acceptable results. Testing with the
flow bias in normal resulted in the system oscillating in and out of
cavitation and the turbine driven EFP tripping on overspeed.
The test
was terminated at this point and Engineering collected all data for
analysis. The licensee's preliminary review determined that bias
settings were higher than required. resulting in the unstable operation.
4
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While engineering review continued, the licensee planned to bypass the
flow bias circuitry, until final determination for long term corrective
i
actions were completed. Since the cavitating venturies were designed to
operate either with or without the EFIC flow bias circuitry, the
licensee has concluded that there should be no impact on system
operations.
c.
Conclusions
The functional test provided evidence that the emergency feedwater
system cavitating venturies would >erform as designed in restricting
pump run out and assuring that NPSi will be assured during accident
conditions.
l
M8.2 FollowUoofMaintenanceOoenItems(62791).
(Ocen) URI 50-302/97-07-03. Reactor Buildino Liner Plate Dearadation
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The inspector reviewed the status of the licensee's efforts to determine
the extent of corrosion damage to the Reactor Building liner plate.
'
During this ins)ection, the inspector observed licensee s visual
inspectors as t1ey were identifying areas of degradation, in preparation
- for calling for the measurement of the depth of individual areas to
determine if repairs will be necessary.
This item will remain open
pending the determination of the full extent of the corrosion of the
liner plate.
(Ocen) URI 50 302/97-07-04. Unanalyzed Combustible Burden in Reactor
Buildina HVAC Ductwork
During this inspection. the inspector was informed that the licensee was
still in the process of determining the condition of the interior of the
Heating. Ventilation and Air Conditioning (HVAC) ductwork inside of the
Reactor Building. This item will remain open pending completion of the
licensee's inspection and evaluation activities.
(Closed) Generic Letter 95 03. Circumferential Crackina of Steam
Generator Tubes
The licensee's responses to GL 95-03 and associated requests for
additional information, were included in NUREG 1604. "Circumferential
-Cracking of Steam Generator Tubes." published A)ril 1997.
NRR close-out
of this GL was documented in an NRR letter to tie licensee dated May 19.
1997. The inspector confirmed that the current OTSG ET inspection scope
included the inspections discussed in Tables 5-1 through 5-4 of NUREG 1604.
(Closed) URI 50-302/96-03 04 Measurement of % Throuah Wall Indications
With an Unaualified Procedure
This unresolved item was addressed in a licensee letter to the NRC.
dated September 23, 1996. As stated in the licensee's letter, the OTSG
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28
tubes in question were removed from service during the 1996 inspection,
therefore there was no violation of the plant Technical Specifications.
The inspector reviewed the current 1997 eddy current analysis guidelines
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and noted no problems involving the use of unqualified procedures or
l
techniques.
(Closed) URI 50 302/96 03 05. Eddy Current Samole Exnansion Based on
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Dearaded Tube Percentaaes
This unresolved item was addressed in a licensee letter to the NRC.
dated September 23. 1996. The licensee's letter documented the
rationale oy which the licensee determined that neither OTSG had been
classified as C-3 during the Spring 1996 inspections.
The inspector
reviewed the. licensee's letter and, after a review of the documentation.
-agreed with the licensee's rationale.
The inspector also reviewed the
current (1977 edition) eddy current analysis guidelines and noted that
-
the sample expansion criteria was clearly defined for this inspection
cycle.
I
llL Enaineerina
El
Conduct of Engineering
El.1 System Readiness Review (SRR) Results Presentation
,
,
a.
Insoection Stone (37551)
The inspector attended the Expert Panel meeting on June 2 and the
Restart Accountability Team 3resentation on June 12 for the SRR of the
Makeup and Purification (MU&)) system to assess the format and content
-
of the meetings.
The inspector also reviewed the disposition of-
selected SRR findings,
b.
Observations and Findinas
The inspector observed that it was impossible to verify the licensee's
expectations and requirements for these meetings since the governing
procedure. System Readiness Review Plan, had not been updated to reflect
the added scope of these two levels of reviews. The licensee stated
that the purpose of the meetings was to ensure a consistent presentation
and format of SRR findings, to identify generic problems that would
expand the scope of subsequent SRR efforts, and to expose appropriate
levels of manaaement to the results prior to final acceptance by the
licensee's restart Janel.
The licensee's attendance expectations were
to have members of .icensing. Engineering, and Operations attend the
meetings. The inspector observed that these objectives were
accomplished by the meetings.
Revision 3 of the SRR Plan was finally
issued on July 2 and the inspector verified the licensee's expectations
were incorporated in the SRR requirements.
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)
The inspector observed that the panel members asked detailed and
challenging questions on the scope of the SRR team's efforts and the
presenter for the MU&P system was very knowledgeable of the effort and
well prepared to answer the questions. The inspector observed that the
scope of the SRR review was focused based on safety significance such
that all portions of the MU&P system were not reviewed in depth unless
y
they had a notable safety function.
Consequently items such as the MU
pumps were reviewed in detail because they served a safety related
function as high pressure injection pumps but components such as letdown
demineralizers were not because they did not serve a safety function.
The inspector did not identify any problems with the sco)e decisions and
recognized this was the within the intent of the SRR to )e able to
,
'
3rovide reasonable assurance of a systems ability to aerform it's design
] asis functions and not to be a comprehensive design Jasis
reconstitution.
The inspector also did not identify any problems with
the disposition of the specific SRR findings.
.
c.
Conclusions
i
The inspector concluded that performing the SRR reviews prior to
developing final written guidance was a poor practice but that level of
reviews was good. The SRR effort identified numerous discrepancies
which were appropriately dispositioned.
E3
Engineering Procedures and Documentation
E3.1
Enaineerina Procedures and Documentation - 10 CFR 50.59 Safety
Evaluations
a.
Insoection Scone (37550)
The inspectors reviewed the licensee's program for performing safety
evaluations for changes and tests, as required by 10 CFR 50.59. This
included review of the licensee's procedure: review of recent 50.59
safety evaluations: review of licensee self assessment in this area: and
discussions with engineering and licensing personnel. The inspectors
reviewed safety evaluations for modifications, procedure changes. UFSAR
changes, and TS Bases changes. . Applicable regulatory requirements
included 10 CFR 50.59. the UFSAR, and Technical Specifications,
b.
Observations and Findinas
The inspectors reviewed CP-213. Preparation of a Safety Assessment
,
and Unreviewed Safety Question Determination (10 CFR 50.59 Safety
'
Evaluation). Revision 3. dated July 3, 1997. This procedure
!
provided instructions for cualified preparers / reviewers to
l
determine if an un-reviewec safety question (US0) was involved in
!
a modification or procedure change. A major revision of the 50.59
'
procedure (program upgrade) was implemented in March 1997, and a
minor revision was implemented on July 3.1997.
The procedure
was supplemented with approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of training to
qualify the preparers and reviewers.
The portion of the procedure
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which addressed the initial screening for UFSAR and T.S.
applicability provided good examples for consideration of response
to screening questions.
The scope definition of the 50.59
procedure was limited in that it did not incluae conditions
outside the FSAR Chapter 14 accident mitigation and did not
address accident prevention. Additionally, a test was described
i
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as involving operation outside the design basis only and did not
I
indicate that a test within the design basis could require a 50.59
evaluation if it impacted FSAR Chapter 14 analysis or other
I
licensee commitments, not included in Chapter 14. such as Station
Blackout or Fire Protection.
The inspectors noted that some
limited /cenditional 50.59 evaluations had been completed which
were bounded by specific cperational modes (i.e. , mode 4/5/6) for
testing and installation and required additional 50.59 evaluation
prior to entering other modes to address the modification
installation in the system. The procedure did not identify a
specific tracking mechanism to assure the additional evaluation
was performed.
The
Assessment Group re procedure also did not require Safety
review when all open items in the modification
package (that could affect the 50.59 US0 determination) were
completed.
The inspectors reviewed examples of 10 CFR 50.59 evaluations
performed for 3rocedure changes and modifications implemented
since the Marc 1 1997, program upgrade.
A listing of 10 CFR 50.59
evaluations reviewed is provided at the end of this report.
Documentation of 10 CFR 50.59 justifications for responses to
screening questions and full 50.59 evaluation questions were
extensive. The inspector identified no examples of incorrect
50.59 evaluations
i.e. . failure to identify a US0 or changes made
improperly under the 50.59 process.
As stated above, some of the 50.59 evaluations were limited or
conditional, requiring tracking to assure that the limits or
conditions will be subsequently addressed.
Examples of 50.59
evaluations which would require additional review are as follows:
Modification Approval Record (MAR) Number 96-10-02-01
.
was related to the installation of EFW cavitating
venturis.
The MAR package concluded that the
modifications do not involve any US0s while the plant
is in Mode 4. 5. or 6.
Thus the US0 determination was
conditional and after installation and testing,
another 50.59 will be required before changing to
Mode 3.
MAR Nos. 96-10-10-01. 02 and 03 evaluated the
+
electrical, structural and physical installation of a
motor operator on the EFW crosstie valve. EFV-12,
respectively.
These MARS did not evaluate the remote
operation of the valve which was to be performed
before the system turn-over to Operations.
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MAR 97-02 17-01 evaluated the addition of a 1500 psi RCS
.
pressure signal for automatic closure of the normal makeup
valve. MUV-27.
The MAR package included several open items.
e.g., case study analysis to determine that closure of MUV-
27 would not reduce the currently analyzed HPI flow
requirements.
{
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The inspectors also noted a UFSAR change contained some incorrect
1
information.
The change dated February 4.1997. in response to PC
97 0178, revised the description of testing performed on EFIC and
EFW components.
The 50.59 evaluation stated that quarterly EFW
flow path position verifications are performed wherein the
Technical Specifications require the flow path positions be
verified every 45 days.
However this discrepancy did not
invalidate the 50.59 screening or result in a USO.
The inspectors also reviewed Nuclear Operations Department Manual.
NOD-55. Control of Design Basis Information. Rev. O. dated
i
December 30._1996.
The procedure defined the design basis and
!
identified the documents that are to used, among others, in the 10 CFR 50.59 US0 determinations.
In Section VI. Responsibilities and
Actions, the 3rocedure stated that Analysis Design Basis Documents
(ABD). descri)ed "... plant system and component performance
characteristics assumed in the various Design Basis Accident (DBA)
analyses presented in the chapter 14 of the FSAR."
The procedure
further stated that the ABDs were intended to "... provide
additional information needed to support safety assessments and 10 CFR 50.59 Unreviewed safety Question Determinations." The
inspectors observed that the use of ABDs in the 50.59 US0
determinations could result in US0 determinations being limited to
FSAR Chapter 14 accident mitigation and not addressing accident
prevention.
The inspectors reviewed the licensee's self assessment of 10 CFR 50.59
activities since the program upgrade. The following Quality Assurance
(OA) Surveillance Reports were reviewed:
OPS-97-0075. Review of EFW Related 10 CFR 50.59 Evaluations
Associated with T.S. Change, dated June 21, 1997
OPS-97-0047. Review Adequacy of 10 CFR 50.59 Training, dated
May 1. 1997
OPS-97-0038. Review of 10 CFR 50.59 Program in Accordance with
NRC Inspection Manual Procedure 37001. dated March 27. 1997
The surveillances were detailed critical assessments of the
s)ecified activities.
Findings were appropriately entered into
t1e station problem identification program (precursor cards
issued) for resolution and tracking.
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c.
Conclusions
The inspectors concluded that the licensee's 10 CFR 50.59 program was
{
good.
The 50.59 procedure and 50.59 evaluations reviewed were general'y
thorough detailed, and comprehensive.
The licensee's self assessments
of performance in this area were adequate.
The inspectors assessed the licensee's performance, relative to the 10 CFR 50.59 Safety Evaluation Program, in the five areas of continuing NRC
concern:
Management Oversight - Good
e
Engineering Effectiveness - Good
e
Knowledge of the Design Basis - Good
e
Compliance with Regulations - Good
e
Operator Performance - N/A
e
E8
Hiscellaneous Engineering Issues
E8.1 100en) IFJ 50 302/95-15-04. Code Reauirement for Thermal Relief Valves
on Decay Heat Removal Heat Exchanaers (37551)
The inspector reviewed Task Interface Agreement (TIA) 96 014 response
from NRR dated April 17. 1997, and discussed the issue with the
licensee.
In summary, the TIA response stated the decay heat removal
heat exchangers (DHHEs) were not provided with overpressure protection
in accordance with ASME Section VIII. The licensee's position that
having an operating procedure to assure overpressure protection by
opening a vent valve when a DHHE was isolated for maintenance purposes
was not an acce3 table substitution for providing pressure relieving
devicer on the
)HHEs.
The licensee understood the NRC's position and
indicated that they will initiate a moaification to install relief
valves on the DHHEs.
This IFl remains open pending review of the
licensee's modification to install relief valves on the DHHEs.
E8.2 (Closed) VIO 50-302/96-06-04. Failure to Perform an Evalyation in
Accordance with 10 CFR 50.59 for Vital Battery Charaer Confiouration
Dif ferent than Described in the Final Safety Analysis Report
a.
Insnection Scope (37551)
The inspector reviewed the corrective actions developed in response to
the violation of July 26, 1996, in a letter dated December 20. 1996.
The licensee developed a safety evaluation.
>er 10 CFR 50.59, on
December 19. 1996.
The inspector reviewed t1e evaluation and found that
it adequately addresses the concern of the violation.
b.
Observations and Findinas
The inspector reviewed CP-111. Processing of Precursor Cards for the
Corrective Action Program, which was revised on November 22, 1996 to
include step 4.4.3.12, which required that a 10 CFR 50.59 evaluation
<
y-
_'
.
33
whenever a potentially significant nonconformance was unresolved for an
extended period of time.
The licensee has determined that ninety days
was the period defined as long-term by the procedure.
The inspector
verified, by the review, that all of the changes to CP-lll had been
implemented.
.-
Licensee Procedure Al-300. PRC Charter, was revised on March 27. 1997.
The inspector verified that the licensee had added detailed expectations
for management review of 10 CFR 50.59 evaluations.
The procedure stated
that the PRC should document the results of the review of an evaluation
'
and make a clear statement of the safety of the plant to operate at
power.
As a result of the violation, the 10 CFR 50.59 safety evaluation
training program was upgraded.
The inspector reviewed that instructor
l
lesson plan, student trainino manual, and class attendance sheets for
I
the upgraded training.
NUCSt 0067.10 CFR 50.59 Safety Evaluation
l
Training - Safety Assessment and Unreviewed Safety Question
l
Determination Training was approved on March 22. 1997.
The inspector
reviewed the lesson plan and determined that the licensee had used NSAC-
125 as the basis for the revisions.
Certain areas, such as the example
of margin of safety, are taken directly from the NSAC document.
This
document had not been endorsed by the NRC and included some
!
interpretations which differed from those used by the NRC.
The
)
inspector discussed this item with the instructor and interviewed
several engineers who had completed the training and determined that the
licensee had taught the more conservative NRC position, but the examples
in the lesson plan reflected the NSAC interpretations.
The licensee was
in the process of reviewing the lesson plan to identify these areas of
difference and correct them.
c.
Conclusions
The corrective actions taken in res)onse to V10 50-303/96-06-04 were
sufficient and warrant closure of t1is item.
The inspector assessed the licensee's performance, with respect to this
restart related issue, in the five NRC continuing areas of concern:
Management Oversight - Adequate
Engineering Effectiveness - N/A
.
Knowledge of the Design Basis - N/A
+
Compliance with Regulations - Adequate
Operator Performance - N/A
.
.
.
.
_
.
l
34
IL Plant Support
P2
Status of EP Facilities. Equipment, and Resources
P2.1 Facility Insoection
,
f
a.
Insoection Stone (82701)
.
The inspectors examined the licensee's emergency response facilities
'
(ERFs) and equipment to determine whether they were maintained in a
state of operational readiness and whether changes made since the last
such inspection (March 1996) were technically adequate and in accordance
with NRC requirements and licensee commitments,
b.
Observations and Findinas
The inspectors toured the ERFs. which included the Control Room (CR).
-
Technical Support Center (TSC). 0)erational Support Center (OSC).
.
Emergency Operations Facility (EO ). and Emergency News Center.
l
Selected equipment and supplies within these facilities were inspected,
including accident monitoring displays and various communications
systems. All inspected equipment was found to be in operable condition.
with one exception -- an operational problem with a computer at the EOF.
When the EOF is activated, data from the Safety Parameter Display System
(SPDS) would be displayed on a standard computer terminal in the
Conference Room for transcription onto the wall-mounted status boards.
The SPDS information could not be selected and displayed from this
computer in late afternoon on June 25. This problem was resolved early
during regular working hours on the following day through replacement of
a circuit board. The functionality of the EOF would not have been
significantly impeded in a real emergency because the SPDS data could
have been obtained through telephonic communication with the TSC until
repairs to the computer in question could be completed. Apart from the
anomaly just discussed, the licensee's ERFs were well designed and
properly maintained.
Miscellaneous radiological instruments and supplies stored in cabinets
in the CR TSC. OSC. and EOF were selectively examined.
The
organization of these cabinets was satisfactory and no significant
discrepancies were identified,
c.
Conclusions
ERFs were well designed and equipped and were maintained at an
acceptable level of operational readiness.
.
.
_
.
l
35
l
P3
EP Procedures and S)cumentation
P3.1 Emeraency Resnonse Plan
>
i
a.
Insoection Scoce (82701)
The inspectors reviewed the licensee's maintenance of the Radiological
-
'
Emergency Response Plan (RERP) and selected commitments therein, and
reviewed recent revisions to the RERP to determine whether changes were
made in accordance with 10 CFR 50.54(q).
i
b,
Observations and Findinas
The version of the RERP in effect at the time of the current inspection
,
was Revision 17. effective April 14. 1997. Since the previously
referenced March 1996 inspection, the licensee had also promulgated
Revision 16 of the RERP. The results of the NRC's review of Revision 16
were communicated to the licensee in a letter dated August 5.1996.
Review of Revision 17 during the current inspection identified several
substantive modifications. Changes in the Emergency Action Levels
-(EAls), which formed the basis for the emergency. classification
methodology, were limited to clarifications of the criteria in the
category of " explosion." Many other changes in Revision 17 were found
to be minor or administrative in nature, including some organizational
modifications.
Between the March 1996 inspection and the close of this phase of the
inspection (i.e.. June 27, 1997), emergency declarations were made by
the licensee on the following dates: September 19 and October 7.1996,
and January 30 and June 17. 1997. All four. declarations were at the
NOUE level.
The January 30. 1997, declaration occurred about 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
after the initiating event warranting an NOUE classification. This
matter was evaluated previously in NRC Inspection Report 50 302/97-04
(Section 01.1) as indicative of a weakness in the licensee's process for
promptly assessing and reporting events.
The inspectors examined
licensea documentation of these declarations, and concluded that each
was correctly and )romptly classified (except as indicated above) based
on the licensee's EAls and that notifications to cognizant offsite
authorities were made in accordance with requirements regarding
timeliness and content.
Documental review confirmed the licensee's conduct of the required
annual review of EAls with State and local governmental authorities for
1996 and 1997.
This review was accomplished annually by means of a
formal presentation to cognizant officials during meetings of the
Crystal River Radiological Emergency Preparedness Task Force.
No
dissenting observations or comments were received from those agencies,
according to the licensee,
v
.
1
.
.
36
c.
Conclusions
RERP Revision 17 was made in accordance with 10 CFR 50.54(q). Emergency
declarations on September 19 and October 7, 1996, and June 17. 1997,
were made in accordance with applicable procedures.
,-
P3.2 Plant Emeroency Procedures (82701)
The inspectors reviewed the licensee's administration of selected RERP
requirements through evaluation of the adequacy of the implementing
details contained in the RERP implementing procedures.
Based upon
selective review, the licensee's implementing procedures were determined
to be generally thorough in terms of detail needed to implement the
various requirements and commitments in the RERP.
No examples of RERP
commitments without appropriate implementing details were identified by
the inspectors.
.
Selected copies of the RERP and its implementing procedures which were
available for use at the CR TSC. OSC, and EOF were checked and found to
be current revisions.
P5
Staff Training and Qualification in EP
PS.1 Trainina of Emeraency Response Personnel
a.
insoection Stone (82701)
The inspector reviewed the Emergency Response Training Program to
evaluate whether emergency response personnel had been initially trained
and retrained annually.
Requirements applicable to this area are
contained in 10 CFR 50.47(b)(2) and (15).Section IV.F of Appendix E to
10 CFR Part 50, and Section 19.0, Radiological Emergency Res]onse
Training, of the licensee's Radiological [mergency Response )lan,
b.
Observations and Findinas
The inspector reviewed Procedure TDP 307. Nuclear Emergency Team
Training Program and TDP 307. Attachment 1. Training Requirements.
Attachment I listed the Emergency Response Organization (ERO) position
and referenced the required training for that position, The inspector
selected approximately twenty members from the Emergency Call Rosters
and reviewed their training records on the licensee's Training--
Information System, a computerized data base.
The inspector verified the twenty ERO members' were initially trained
and that their retraining was up-to-date.
The inspector also verified
selected individual computerized training records against copies of
training attendance sheets.
No deficiencies were identified.
-
--__ ____
_
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ - _ _
_
_ _ _ _ _ _ _ _ - _ . _
'
.
,
-
-
.
,
i
37
The inspector reviewed three lesson plans:
Emergency Coordinator. NUCTRE
007/A Revision 14. Initial and
Continuing Training.
Dose Assessment Team NUCTRE - 003/A Revision 7. Initial and
Continuing Training, and
-
Radiological Monitoring Team. NUCTRE - 009/A Revision 3. Initial
.
and Continuing Training
Each lesson plan contained good learning objectives which were
adequately covered in the lesson plan. The lesson plans were well
organized and of sufficient detail.
A test given for each lesson plan
i
adequately tested the student's knowledge of the subject.
The inspector noted and the licensee confirmed that drill participation
.
was not a qualification requirement.
The inspectors accompanied by a member of the licensee's staff
interviewed five ERO members qualified as an Emergency Coordinator (EC).
Two interviewees were TSC ECs. and three interviewees were Senior
Reactor Operator (SRO) control room ECs. The interviews were conducted
in order to assess both:
the effectiveness of Emergency Preparedness Training, and
a
to ascertain if the Eats were clearly and unambiguously written;
the interviewees understood the EALs: and the interviewees could
use the EALs to correctly classify events.
All five interviewees were asked the same questions from en inspector
4
prepared interview questionnaire.
The interview was divided into two
parts. The first part asked basic questions from EM 202. Duties of the
Emergency Coordinator Revision 55.
In the second part interviewees
were asked to classify simple but direct scenarios,
in the first part of the interviews, the interviewees answered most of
the questions satisfactorily. Three interviewees incorrectly state the
minimum Protective Action Recommendation (PAR) for a General Emergency
(GE).
The minimum PAR had been recently changed.
In the second part of the intervie's the inspector noted numerous
inconsistencies in classification and interpretation of the EALs. In
comparing the interviews responses, the inspector noted different
classifications in 10 of the 13 scenarios presented to the interviews.
Some examples of differences in scenario classifications were:
e
a loss of (A) Vital DC Bus for 13 minutes was classified as an
Alert and no classification
_ .
_ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - -
.
-
-
38
four of the interviewees classified an identified leak of 45 gpm
e
j
as a NOUE even though there was not an applicable EAL
inconsistency as to Mode applicability of some EALs
e
inconsistency in interruption of particular words or phrases.
As
e
y
an example:
For " loss of Cold shut Down",
one interviewee stated that the EAL was only applicable in
-
Mode 5.
one interviewee stated the EAL was applicable in Mode 1 and
-
applied to the complete loss of only one system, and
_
another stated the EAL was applicable in Mode 1 but you had
-
to lose all Cold Shut Down capability
The inspectors observed basically the same response for loss 6f Hot Shut
i
l
Down.
Other examples noted by the inspectors concerning the licensee's ability
to effectively use the EALs were:
the delay in classifying the transformer explosion at the fossil
unit as a Notification Of Unusual Event nr January 1. 1997, and
in the licensed operator upgrade exam the week prior to this
.
inspection three of the four Senior Reactor Operator license
candidates incorrectly classified an event during the Simulator
Exam. This was documented in NRC Inspection Report 50-302/97-300.
The inspectors * concern regarding the variation in classification noted
during the interviews was discussed with the licensee.
The inspector
stated to the licensee that the cause of the variance in classification
appeared to be a combination of weakness in EAL basis training and an
apparent ambiguity of the licensee's EALs.
The inspectors informed the
licensee that the unacceptable variance in classifying scenarios among a
'
representative sample of Emergency Coordinators would be tracked as
Inspector Follow-up Item (IFI 50-302/97-08-03). Unacceptable Variance in
Classifying Scenarios Amorg a Representative Sample of Emergency
Coordinators,
c.
Conclusions
The licensee maintained an adequate initial training and annual
retraining arogram. Individual member's ERO training was maintained
current.
ERO lesson plans and exams were well organized and of good
detail.
Interviews revealed a considerable variance in classifying
basic scenarios.
The inspector concluded that the variance was a
combination of weakness in EAL basis training and an apparent ambiguity
of the licensee's EALs.
_ _-
,
.
gio*
b
39
P5.2 Emeraency Plannino Drills
a.
Inspection Scope (82701)
The inspectors reviewed drill documentation to evaluate whether the
licensee was conducting the types and number of drills identified in
f
Section 18.3, Drills and Exercises Requirements, of the licensee's RERP.
Requirements applicable to this area are contained in 10 CFR 50.47(b)(14),Section IV.F(1) of Appendix E to 10 CFR Part 50, and the
licensee's RERP.
b.
Observations and Findinas
The licensee used the first responder concept in staffing the ERF,
he
inspector verified that the licensee maintained approximately four
personnel qualified in each ERF position.
The inspector reviewed Attachment 2. Drill and Exercise Requirements, of
Radiological Emergency Plan (REP)-06 Schedule For Radiological
Emergency Response Plan Maintenance. REP-06 im)lemented Section 18.3,
Drill and Exercise Requirements, of the RERP.
REP.-06 listed the required
drills and frequency as:
Monthly - Communication Drills
Quarterly - Fire Drills
Semiannual - Health Physics Drills
.
Annually
Annual RERP Exercise, Medical Emergency Drill.
.
Radiological Drill, Radiological Sampling Drill, and Shift
Augmentation Drill
The inspector noted that the RERP permitted and, on occasion, the
licensee had performed drills in parallel with the annual exercise or
other drills.
The inspectors reviewed documentation which indicated
that the licensee had conducted their required drills.
No additional
drills were performed.
The inspectors verified from drill documen+ tion
that drills were critiqued and requirements and items identified
needing correction or improvement were tracked on the licensee's
corrective action appropriate tr ucking system.
The licensee's Emergency Planning Logbook indicated that the licensee
had conducted quarterly TSC and OSC activations. The licensee stated
that during some of the activations, table to) exercises were conducted
and response teams were dispatched. These taale top sessions lasted one
l
and a half to two hours.
On other TSC/OSC activations, procedure
changes were discussed for approximately thirty to forty-five minutes.
No supporting documentation was available to note what was covered
during the these quarterly TSC/OSC activations.
l
_
_
.
,
40
c.
Conclusions
The licensee met the drill commitments in their Radiological Emergency
Response Plan and REP 06. Orills and Exercise Requirements,
i
P6
EP Organization and Administration
'
P6.1 Review of New Orcanization/Manaaement Chanaes
l
a.
Insnection Stone (817_Q11
The inspectors reviewed this-area to determine if any changes in the
emergency organization or management control systems had occurred which
could adversely affect the implementation of the Emergency Preparedness
(EP) program.
,b.
Observations and Findinas
'
The organization and management of the EP 3rogram were reviewed and
discussed with licensee representatives,
iumerous management personnel
changes had been made since the March 1996 inspection. The individual
serving as Manager. Radiological Emergency Planning (MREP) had been in
I
I
that position for about 10 years.
However. all personnel in his
management reporting chain were new in their positions since March 1997,
including (in organizationally ascending order) the Director. Nuclear
Regulatory Affairs. the Vice President. Nuclear Production, and the
Senior Vice President. Nuclear Operations.
The inspectors interviewed
various cognizant staff and managenent personnel in an effort to
ascertain the effects of these changes on the EP program at Crystal
River. No adverse impacts were identified.
The inspectors noted that
the new management personnel originated and/or supported several major
EP program initiatives under consideration.
- Almost all of the new manacement personnel were still in the process of
being trained for their ERO positions.
Staffing depth for each key ERO
position was at least three persons: an increase to four or five for
each position was anticipated when the training of new managers was
completed.
c.
Conclusions
No degradation had occurred in the organization or management of the
emergency preparedness program.
Emergency preparedness appeared to be
receiving strong management support at Crystal River.
9
O
'
.
-
41
P7
Quality Assurance in EP Activities
P7.1 10 CFR 50.54(t) Audit nf EP Proaram
a.
Insoection Stone (82701)
l
f
The inspectors reviewed this area to assess the quality of the required
audit and to verify that the audit met the requirements of
b.
Observations and Findinas
The inspectors reviewed documentation associated with the EP program
audit conducted in 1996 by the licensee's Quality Assessments group.
1he inspectors reviewed the " Audit Report of Fire Protection / Emergency
Planning", conducted May 20-June 7,1996, and documented in
Report No. 96 04-FPEP.
This audit identified four " strengths ~ and five
-
" weaknesses ~ in EP.
This audit was judged to be thorough and
independent, and the nature of the identified issues indicated a
thorough understanding of the EP area by the auditors.
The audits
provided evidence of the licensee's ability to self-identify EP program
deficiencies.
,
The EP staff began a self assessment program in January 1997. The
inspectors reviewed the four reports generated thus far, assessing EP
program areas such as capabilities for responding to a multiple-casualty
emergency, offsite communications following a severe natural event and
the program of simulator-driven integrated drills. The licensee planned
to perform about 10 focused self assessments annually.
The inspectas
determined that the self assessments were producing useful results.- and
were being performed effectively.
C.
Conclusions
The Quality Assessments audit for 1996 fully satisfied the 10 CFR 50.54(t) requirement for an annual independent-audit of the EP program.
P7.2 Licensee's Corrective Action Proaram For Drill Comments and Issues
a,
insoection Scoce (82701)
This area was-reviewed to evaluate the licensee's corrective actions to
comments and issues identified in their drills. Requirements applicable
to this area are contained in 10 CFR 50.47(b)(14).
.
=-
-p
A
.
_.
.
42
b.
Observations and Findinas
The licensee used two tracking systems:
Nuclear Operations Tracking and Expediting System (NOTES), a
.
computer listing of the licensee's corrective action system
.-
issues.
Nuclear Operations Commitment System (NOCS), used to track
commitments in procedures and plans.
Examples were:
Emergency
Preparedness Plan, Security Plan, and Fire Protect on Plan.
The inspectors performed a limited review of CP 111 Processing of
Precursor Cards for Corrective Action Program. CP-111 was used by the
Emergency Preparedness group to track findings from audits, drills, and
exercises.
The inspectors reviewed findings from the licensee's drill critiques,
and compared these findings to NOTES.
The inspector verified that drill
critique comments and audit findings were being tracked in accordance
with CP-111.
The inspectors reviewed two completed packages from the Emergency
Preparedness NOTES and NOCS list to evaluate the adequacy of closure for
items being tracked or resolved.
Package 24085 - Was satisfactorily closed.
.
Package 24194 - Was in response to NOCS Commitment 40104.
.
Commitment 40104 was in response to a violation in 1987 (Violation
50 302/87-36 01). The a) parent cause of the violation was Table
8.1, Classification of )ostulated Accidents was not revised in the
RERP to address the EAL changes in EM-202. This caused an
inconsistency between the two documents. The description of
Package 24194 stated: " Emergency Plan Implementation Procedure
(EPIP) changes that do not decrease the effectiveness of the RERP,
but are considered significant, will require revision of RERP
prior to implementation".
The implementing reference, REP-10, did
not contain this guidance.
'
In their response, the Emergency Preparedness group stated that
Attachment 5 of REP-10 flags
nsideration of revising the RERP
prior to the procedure or program change. The statement they
referenced as flagged was:
Does This Change Affect Non-FPC
Organizations?" Emergency Preparedness agreed in their response
that the " flag" was unclear and that they would clarify the
commitment in the next revision of REP-10 which was scheduled for
early 97.
As of the date of the inspection, the statement had not been
clarified in REP-10, and package 24194 had been signed off as
complete.
.-
-_
_
_
_
_ _ -
_ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _
-
.
,
i
.
43
'.
After discussions with the licensee, the inspectors determined that
drill comments and Emergency Preparedness issues were being resolved.
The need to improve the resolution of Emergency Preparedness issues that
were being tracked was discussed with the licensee. The licensee agreed.
and prior to the end of this inspection, had initiated the process to
revise REP-10 to adequately close package 24194.
>
c.
Conclusions
'
-
The inspectors concluded that the licensee was documenting and tracking
their drill comments and Emergency Preparedness commitments.
Premature
closure was identified as one of two cases reviewed.
56
Security Organization and Administration
!
S6.1 Effective July 7,1997. Nuclear Operations Access Control began
reporting to Nuclear Security.
F3
Fire Protection Procedures and Documentation
F3.1 All Fire Service Pumos Renderep inocerable
a.
insoection Stone (71750)
The ins)ectors reviewed the events which led to all three fire service
pumps (:SPs) being rendered inoperable during the performance of a post
,
'
maintenance test.
,
b.
Observations and Findinas
On May 15, 1997, work was completed on FSP-2A (pump bearing replacement)
and a post maintenance test was performed using Procedure SP-363. Fire
Protection System Tests. Revision 29.
When SP 363 is used, all three
FSPs are declared inoperable due to the controllers for FSP-2A and FSP-
l
2B being turned off and the breaker for FSP-1 being opened,
This
condition was not recognized until the oncoming shift supervisor
questioned the outgoing shift supervisor whether he had considered the
inoperability of all FSPs due to the performance of this 3rocedure. At
this point the surveillance was stopped and FSP-1 and FS)-2B were
'
returned to service. The pumps were out of service for a total of 110
minutes.
PC 97-2049 was written to implement corrective action and
assigned a grade level B.
An immediate action taken by the licensee
.following this event was to place an administrative hold on SP 363.
All three FSPs being rendered inoperable requires entering Fire
'
Protection Plan (FPP) Table 6.2a. Action 1B which states, in part:
restore at least one inoperable pump to operable status as soon as
possible; notify the NRC Operations Center within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s: submit a
special report to the Regional Administrator within 14 days. The
inspectors verified that all required notifications were accomplished.
The FPP did not have a provision for equipment outage time while
maintenance or surveillance was performed: however, the licensee's
. - -
- .
.__ .. .
. __-
-. - .
--_
.
.- _
-.
. _ . .
.
- .-
4
-
.
44
special report to the NRC indicated that a future revision to the plan
would include equipment outage time and/or compensatory measures. As an
interim measure, each of tne fire service surveillance procedures will
be reviewed for operability impact.
The licensee was continuing to work
this issue at the end of the inspection period but appeared to
understand the problem and how to correct it to prevent recurrence.
It was identified by the licensee that a related PC had been written on
March 4, 1997.
PC 97-1537 discussed the potential for SP-363 to cause
all three FSPs to be rendered inoperable several times during the
performance of the procedure.
This PC was assigned a grade level D with
a response requested, but was not acted upon in a timely manner because
the fire protection department determined the procedure would not be
used for another 18 months (surveillance frequency).
If action had been
taken following the initial identification of this problem, the May 15th
event could have been precluded.
This licensee-identified and corrected
violation is being treated as a Non-Cited Violation (NCV 50-302/97-08-
04). Fire Service Pumps Rendered inoperable During Post Maintenance
<
Test.
c.
Conclusions
The inspectors concluded that the fire protection department failed to
4
take timely and adequate corrective action when it was determined that
'
the use of Procedure SP-363 could potentially cause all three FSPs to be
rendered inoperable.
It was at this time that SP-363 should have been
placed on an administrative hold to prevent usage until the FPP could be
changed to include equipment outage times and/or compensatory measures,
and for associated procedures to be revised.
The inspectors considered
this an example of untimely and inadequate corrective actions on the -
part of the fire protection department.
1,.
Manaaement Meetinas
X1
Exit Meeting Summary
The inspection scope and findings were summarized on June 20. June 27.
July 11 and July 14. 1997.
Proprietary information is not contained in
this report.
Dissenting comments were not received from the licensee.
,
'
X3
Management Meeting Summary
X3.1- A meeting was held at the Crystal River training facility on June 19.
1997, to discuss Restart status.
A meeting summary was issued on June
26. 1997.
7
.-
e
_.
.
45
PARTIAL LIST OF PERSONS CONTACTED
Licensees
R. Anderson Senior Vice President. Nuclear Operations
J. Baumstark. Directer. Quality Programs
'
J. Cowan. Vice President. Nuclear Production
-
R. Davis. Assistant Plant Director. Operations and Chemistry
R. Grazio. Director. Nuclear Regulatory Affairs
G. Halnon. Assistant Plant Director. Nuclear Safety
B. Hickle. Director. Restart
J. Holden. Director. Nuclear Engineering and Projects
D. Kunsemiller. Manager. Nuclear Licensing
M. Marano. Director. Nuclear Site & Business Support
C. Pardee. Director. Nuclear Plant Operations
M. Schiavoni. Assistant Plant Director. Maintenance
J. Blake. Senior Project Manager. Region II (June 16 through 20, 1997)
H. Christensen. Engineering Branch Chief. Region 11 (June 18 through 19. July
11, 1997)
B. Crowley Reactor Inspector. Region II (June 16 through 20. 1997)
M. Dapas. EDO Coordinator (June 18 through 19. 1997)
J. Hayes. NRR (June 16 through 18, 1997)
F. Hebdon, Director. Directorate 113 NRR (July 10 through 11. 1997)
G. Hopper Reactor Engineer. Region 11 (June 16 through 19. 1997)
J. Jaudon. Director. Division of Reactor Safety. Region II (June 18 through
19, 1997)
C. Julian. Technical Assistant. Region II (June 18 through 19, 1997)
J. Kreh. Radiation Specialist. Region II (June 23 through 27, 1997)
K. Landis. Branch Chief, Region II (June 18 through 20. July 10 through 11,
1997)
J. Lenahan Reactor Inspector. Region 11 (July 7 through 11, 1997)
- R. Moore Reactor Inspector Region II (July 7 through 11, 1997)
L. Plisco. Deputy Director. Division of Reactor Projects. Region 11 (June 18
through 19. 1997)
L. Raghaven. Project Manager. NRR (June 18 through 19. July 7 through 11.
1997)
G. Salyers. Emergency Preparedness Specialist. Region 11 (June 23 through 27,
1997)
R. Schin. Reactor Inspector. Region 11 (June 16 through 20. July 7 through 11.
1997)
P. Steiner, Reactor Engineer. Region 11 (June 16 through 19. 1997)
T. Peebles. Operator Licensing Branch Chief. Region II (June 18 through 19,
1997)
INSPECTION PROCEDURES USED
IP 37550:
Engineering
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying. Resolving and
.
-
. .
_
_
-
_ _ _
_ - _ _ _ _ _ _ ,
- - - - -
'
.
.
.
46
Correcting Problems
IP 50002:
IP 61726:
Surveillance Observations
'P 62700:
Maintenance Implementation
TF 62707:
Conduct of Maintenance
10 7U07:
Plant Operations
.-
iP 71750:
Plant Support Activities
iP 82701:
Operational Status of the Emergency Preparedness Program
IP 92901:
Followup - Operations
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Tygg Item Number
Status
Descriotion and Reference
50-302/97-08-01
Open
Inadequate Procedure and Corrective
l
Action for NRC Reporting
Requirements. (paragraph 07.2)
!
IFI
50-302/97-08-03
Open
Unacceptable Variance in Classifying
Scenarios Among a Representative
,
Sample of Emergency Coordinators.
{
!
(paragraph P5.1)
l
l
Closed
_Tygg Item Number
Status
Descriotion and Reference
I
GL
Closed
Circumferential Cracking of
Steam Generator Tubes.
(paragraph M8.2)
50-302/96-03-04
Closed
Measurement of % Through Wall
Indications With an
Unqualified Procedure.
(paragraph M8.2)
50-302/96-03-05
Closed
Eddy Current Sample Expansion
Based on Degraded Tube
Percentages. (paragraph M8.2)
50-302/96-06-04
Closed
F6;iure to Perform an-
.
Evaluation in Accordance with
'
10 CFR 50.59 for Vital P.attery
Charger Configuration
Different than Described in
the Final Safety Analysis
Report. .paragraf TS.2)
~
_ _ - _ _ _ _ _ _ - _ _ - _ _ _ - _ - - -
-
-
'
,
_
47
50-302/97-08-02
Closed
Failure To Implemen+. Licens9
Condition Surveillance
Requirements Associated with
Improved Technical
Specification Implementation.
(paragraph 08.1)
50-302/97-08-04
Closed
Fire Service Pumps Rendered
Inoperable During Post
Maintenance Test. (paragraph
F3.1)
Discussed
'
'
J.Y2g Item Number
Status
Descriotion and Reference
97-094 (01013. 01023)
Open
Repeat Failure to Make Timely
Reports to the NRC. (paragraph
07.2)
,
50-302/97-01-04
Open
Failure to Perform Technical
'
Specification Surveillance for
Spent Fuel Pool Level.
(paragraphs M1.2. M1.5)
50-302/97-07-03
Open
Reactor Building Liner Plate
Degradation. (paragraph M8.2)
50-302/97-07-04
Open
Unanalyzed Combustible Burden
in Reactor-Building HVAC
Doctwork. (paragraph M8.2)
IFI
50-302/95-15-04
Open
Code Requirement for Thermal
Relief Valves on Decay Heat
Removal Heat Exchangers.
(paragraph E8.1)
_-
_- _ -
- _ - -
..
. .
.
..
. . ..
4
.
I
i
48
LIST OF ACRONYMS USED
'ABD
Analysis Design Basis Documents
-
AI
Administrative Instruction
--
BSP
Building Spray Pum)
-
Corrective Action Review Board
-
CFR
Code of Federal Regulations
-
-
'
CM=
Corrective Maintenance
-
Compliance Procedure
-
- CR
Control Room
-
-CR3
Crystal River Unit 3
-
Design Basis Accident
-
Design Basis Document-
-
l
- DHHE
-
Decay Heat Removal Heat Exchangers
l
Emergency Action level
-
- EC
Emergency Coordinator
-
EDBD-
Enhanced Design Basis Document
-
-
-
Emergency Feedwater Initiation and Control
Emergency Feedwater
-
EM -
-
Designation used for RERP Implementing Procedures
-
-
Emergency Plan Implementing Procedure
-
-
Emergency Response Facility (TSC. EOF. OSC)
-
Emergency Response Organization
-
FPC-
Florida Power Corporation
-
-
Fire Protection Plan
-
Fire Service Pump
General Emergency
-
GL
-
Generic Letter
Heating Ventilation and Air Conditioning
-
IFI
Inspection Followup Item
-
Modification Approval Record
-
MOVATS -
Motor Operated Valve Analysis and Test System
-
~ Maintenance Request
MREP
-
Manager. Radiological Emergency Planning
-
- MT
Magnetic Particle Examination
-
- M&TE
Measuring and Test Equipment
--
MUV
Make-up Valve
-
Non-cited Violation
-
-
NOCS
-
Nuclear Operations Commitment System
NOTES
Nuclear Operations Tracking and Expediting Svstem
-
NOTIS -
Nuclear Operations Training System
-
Notification of Unusual Event
NOV-
-
-
Net Positive Suction Head
NP&SM -
Nuclear Procurement and Storage Manual
N0A
-
Nuclear Quality Assessments
t
,
'
.
.
-
-
,
49
NRC-
-
Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
1
-
Operability Concerns Resolution
-
Operational-Support Center
-
Once Through Steam Generator
-
Protective Action Recommendation
-
PC
Precursor Caro
--
-
'
Preventive Maintenance
-
!
PR
Problem Report
-
'
Plant Review Committee
-
Liquid Penetrant Test
-
.PWHT
Post Weld Heat Treatment
-
GA
~0uality Assurance
-
OPS-
Quality Programs Surveillance
-
Reactor Building
-
Reactor Coolant Pump
-
-
REA
Recuest for Engineering Assistance
-
Raciological Emergency Plan
-
-
Radiological Emergency Response Plan
Shift Manager
-
Surveillance Procedure
-
Safety Parameter Display System
-
SR
-
Surveillance Requirement
-
Senior Reactor Operator
SRR
System Readiness Review
-
-
System. Structure or Component
5S00
Shift Supervisor on Duty
-
Task Interface Agreement
-
TS
-
Technical Specification
-
-
Unresolved item
-
Unreviewed Safety Question
VTolation
-
Work Request
-
i
. _ _ _ _ _ _ _ _ - _ _ _ _ _
_
_
.
.
.
.
50
LISTING OF 10 CFR 50.59 EVALUATIONS REVIEWED
FSAR and ITS Change for MAR 96-11-01-01, dated April 14. 1997
PT-308. BSP-1A Power and Flow Measurements for EGDG-1A KW Loading
Verification Rev. 5. dated April 18, 1997
)
.
~
PM-172, Plant Safety Equipment Checks, Rev. 10, dated February 21. 1997
i
SP-354A. Monthly Functional Test of the Emergency Diesel Generator EGDG-1A,
l
Rev. 44, dated March 5. 1997
l
SP-340F. Makeup Pump 1C and Valve Surveillance. Rev. 16. dated March 19, 1997
!
!
SP-702E. Shutdown Margin Boron Surveillance, Rev. O, dated March 17, 1997
l
SP 0711B, Core Flood Tank 1A Boron Surveillance Program, Rev. 0
OP-608. OTSG's and Main steam Systems. Rev.47, dated May 7, 1997
OP-408 Nuclear Services Cooling System Rev. 83, dated. February 14, 1997
'
OP-403B, Chemical Addition Boric Acid System. Rev.18. dated April 29, 1997
CP-147, Control Complex Habitability Envelope Breaches, Rev. 2. January 27,
1997
CP-151 External Reportin9 Requirements. Rev. O. dated June 18, 1997
OP-304 Soluble Poison Concentration Control. Rev. 9. dated May 31, 1997
PM-172 Plant Safety Equipment Checks. Rev 9
CH-518B. Waste Gas Tank 3B Sampling (CE-113). Rev. O
MAR 96-10-05-01. Emergency Diesel Generator (EDG) Parts Replacement / Power
Upgrade, dated December 16. 1996
Mar 97-01-04-01. Installation of New Er.ergency Feedwater (EFW) Flow
Instrumentation, dated June 25, 1997
MAR 96-03-12-01. EDG Indication Upgrade, dated April 12. 1997
MAR 96-10-02-01. Emergency Feedwater Cavitating Venturis, dated March 26. 1997
MAR 96-11-01-01. Automatic Opening of ASV-204. dated April 14. 1997
MAR 96-11-04-01. Emergency Feedwater Initiation and Control System Level
Control Improvement, dated June 13. 1997
MAR 97-02-18-02, 0HV-3 and DHV-4 Cable Reroute. Revision 0
PEERE 1497. BSP-001A Impeller Rework, dated April 10. 1997
~
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..
.
.
.
.
..
,,
2
1*
302/95-22-01
Nine examples of makeup
95-126
VIO 01013
Failure to comply with procedures and
tank operation outside
administrative controls related to
of the acceptable
maximum make-up tank pressure on numerous
operating region
occasions
302/95-22-02
Two examples of an
95-126
VIO 02013
F6ilure to conduct tests in accordance
'
unauthorized test
with a valid safety evaluation report on
two occasions
302/95-22-03
Three examples of
95-126
VIO 03013
Failure to identify 3romptly the
inadequate corrective
significant errors tlat were presented in
action
OP-1038. Curve 8 and in the calculations
that were basis for the curve
95-126
VIO 04013
Failure to 3revent operation outside of
the design ] asis95-126
VIO 08014
Failure to identify the root cause and
take steps to preclude repetition of a
i
significant condition adverse to quality
related DG oil tank levels
302/95-22-04
Four examples of
95-126
VIO 05013
Makeur tank procedure limits for makeup
inadequate design
tank pressure failed to meet the ECCS
control
design basis95-126
VIO 06013
Failure to correct translate the cesign
basis for the ECCS into the FSAR
95-126
VIO 07013 '
Procedures E0P-07 and 8 failed to meet
the ECCS design basis during April 8.
1993 and March 22. 1995
95-126
VIO 09014
Failure to establish an adequate
procedure to verify the mini ,um required
water volume in each of two fire water
storage tanks
_ _ _ _ _ _ _ _ _ _ _ _ _ -
- _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _
.,
-
3
i~ ~
302/96-10-01
FaH are to follow
96-316
VIO 01014
Failure to follow procedure FP-203
'
procedure FP-203
resulting in misplacing
and collision of fuel
assemblies
,
302/96-10-02
Failure to assure that
96-316
VIO 02014
Failure to promptly identify and correct
the root cause analysis
the fuel handling event
and corrective actions
,
taken to preclude
repetition were adequate
302/96-18-01
Failure to have adequate
97-012
VIO 01013
Failure to implement the Security plan
procedures
302/96-18-02
Failure to respond to a
97-012
VIO 01023
Failure to respond to an intelligent
protected area alarm
multiplexer alarm
302/96-18-03
Failure to assess m re
97-012
VIO 01033
Failure to assess more than ore protected
l
'
than one protecten
ea
area alarm
alarm
302/96-18-04
Failure to maintain
97-012
VIO 01043
Failure to maintain protected area
'
protected area barriers
barriers
302/96-18-05
Inadequate arms97-012
VIO 01053
Failure to properly secure arms in a
repository
repository
302/96-18-07
Failure to adhere to
97-012
VIO 01063
Failure to comply with the requirements
. _ _ _ _ _ _ _ _ _ -
_ _ - -
.
4
4-
302/96-12-02
EDG Loading US0's three
96-365
VIO 01012
In A]ril 1996. the licensee made a change
examples
to tie facility as described in the FSAR.
which involved three US0s. without prior
302/96-12-03
Inadequate corrective
Commission Approval.
actions for 10 CFR 50.59
'
Evaluation
96-3R
VIO 01022
In April 1996. the licensee made a change
'
to a procedure as described in the FSAR.
302/96-12-04
Use of unverified
which involved three US0s. without prior
calculations to support
Commission approval
modifications96-365
VIO 01032
In June 1990 the licensee made a change
302/96-19-01
Three inadequate
to a procedure as described in the FSAR.
i
procedures for
which involved a US0. without prior
'
containment penetrations
Commission approval
392/96-19-02
Inadequate corrective
96-365
VIO 01042
In May 1987 and in March 1992. the
actions for inacaguate
licensee made changes to the facility as
containment penetrations
described in the FSAR. which involved a
US0. without prior Commission approval
302/96-19-03
Inadequate 10 CFR 50.59-
saferv evaluation for
96-365
VIO 01052
In May 1996, the licensee made changes to
moditication
the facility which involved a US0.
without prior Commission approval
302/96-19-04
Failure to update
applicable design
96-365
VIO 01062
The 10 CFR 50.59 evaluation concerning
documents
Boron dilution was inadequate
302/96-19-05
Failure to include
96-465
VIO 02013
Failure to establish to assure that
applicable design
a)plicable regulatory requirements and
information
t1e design basis were correctly
translated into specifications.
302/96-19-06
Inadequate 10 CFR 50.59
procedures. and instructions.
safety evaluation for
modification
96-527
VIO 03013
Failure to correct condition adverse to
quality and failure to take measures to
302/96-19-07
Inadequate 50.59
assure that corrective actions were taken
evaluation for post LOCA
to preclude repetition of significant
NOTE: The EEIs se v. rated from EA-96-365.
302/96-19-08
Error in design
465, and 527 by t1e bold vertical line do
calculations for SW
not directly correlate to a specific EA
system heat loads
but were split as part of multiple EAs.
_ _ _ _ _ _ -
_ _ - _ _ _ _ _ _ _ _
_
-
.,
-1
-
' '
5
t*
I
302/97-03-01-
Failure to protect
97-161
VIO 01013
In 1990 NRC safeguards information were
safeguards information
left unattended
97-161
VIO 01023
On March 15. 1997 152 aperture cards
containing safeguards information were
i
i
left unattended
302/97-04-01
Failure to make an
97-094
VIO 01013
Failure to make a report to NRC withi
emergency phone report
one hour requirements
within time requirements
VIO 01023
Failure to submit a report to NRC within
30 days
302/97-04-02
Failure to carry a
97-094
VIO 01043
Failure to carry a suspected reportable
suspected reportable
issue to the shift manager for review
issue to the shift
manager
302/97-04-03
Repeat failure to report
97 094
VIO 01033
Failure to report to the NRC a
outside design basis
vulnerability in safeguard system. the
conditions
protected area boundary. within one hour
302/97-06-01
Inadequate safety
VIO 01013
Inadequate safety evaluations for added
evaluations for added
operators actions for design basis SBLOCA
operators actions'for
mitigation
design basis SBLOCA
mitigation
_
_ _ _ _ - _ _ _ _ _ .