ML20203A206
| ML20203A206 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 12/04/1997 |
| From: | Christensen H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20203A171 | List: |
| References | |
| 50-302-97-14, NUDOCS 9712120042 | |
| Download: ML20203A206 (87) | |
See also: IR 05000302/1997014
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U. S. NUCLEAR REGULATORY COMMISSION
REGION 11
SAFETY SYSTEM FUNCTIONAL TEAM INSPECTION
Docket No.- 50-302
License No.: DPR-72
Report No.: 50-302/97-14
Licensee: Florida Power Corporation
Facility: -
Crystal-River 3 Nuclear Station-
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Location: 15760 West Power Line Street
Crystal River. Florida
Dates: October 6 through 24, 1997
4
Team Leader: W. Holland. Senior Reactor inspector.
Division of Reactor Safety (DRS)
Inspectors: M. Shannon. Senior Resident Inspector. Division of Reactor
Projects (DRP)
R. Schiii. Senior Reattor Inspector. DRS
N. Merriweather. Senior Reactor Inspector. DRS
L. Garner Project Engineer. DRP
R. Moore. Reactor Inspector. DRS
R. Landry. Senior Reactor Engineer. Office of Nuclear
Reactor Regulation (NRR)
W. Mortensen. Digital Instrumentation & Control Engineer.
Approved By:
Ararold O. Christensen. Chief
/b!Y!97
Engineering Branch Date'S'tJned
Division of Reactor Safety
!
(
Enclosure 2
9712120042 971204
{DR ADOCK 05000302
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. EXECUTIVE SUMMARY
Crystal River Nuclear Plant. Unit 3
_
NRC Inspection Report 50-302/97-14
This team inspection involved a Safety System Functional Inspection of the
Makeup and Purification System and Decay Heat Removal System. The inspection
objective was to assess the operational performarice capability of the selected
safety systems through an in-depth, multi-disciplinary engineering review to
verify that the selected systems were capable of performing their intended
safety functions. The inspection was conducted using Inspection Procedure
93801. " SAFETY SYSTEM FUNCT10N#1 INSPECTION (SSFI)." The report ~ covered a
2-week period of on-site inspection by inspectors from Regicq Il and NRR.
Operations
. A negative observation was noted for not actively monitoring operating
. plant equipment (Section 02.1). ~ - , . -
. -+ .
.; . ..
. A weakness was identified due to a lack of consistent g'uidance in
operator surveillance activities and lack of guidance in operator logs
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(Section 02.1).
. A weakness was identified for an error in documenting required
surveillance data (Section 02.1). ,
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. An operation's weakness was identified for not continuing to identify !
deficient conditions on the heat trace system and disabling related l
control room alarms (Section 02.1).
'
. The adequacy of the system 03 crating procedures for the Makeup and
Purification System and the 3ecay Heat Removal System could not be
determined due to the large number and types of changes pending. An
open item was identified to review the adequacy of these procedures
(Section 03.1).
. A weakness was identified for not providing a cc ,istent identification
for and maintaining the proper locat.on of the B Makeup Pump breaker
lock keys (Section 03.1)
. The alarm response procedures reviewed were ade'quate. Operator actions
l for valid alarms were typically superficial act. ions (Section 03.1).
. A weakness in the licensee self-assessment program was identified for
not issuing a Precursor Card (PC) when the licensee discovered that a
i procedure change. recommended by the Plant Review Committee to be
deleted from a proposed procedure revision. was incorporated into the
revised procedure (Section 03.2).
. Operator knowledge and understanding of the Makeup and Purification
System and Decay Heat Removal System operations were good and were
considered a positive observation (Section 04.1).
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. Control room activities were observed to be conducted in an overall good
manner. During plant tours operators were recording log readings and
equipment checks as required. However, a lack of specific written
guidance as to management's expectations for the conduct of equipment
checks was a weakness (Section 04.2).
. The Replacement Operator Training lessons were generally consistent with
svstem operating procedures and the enhanced design basis documents
(Section 05.1).
. Job Performance Measures were adequate to familiarize operating
personnel Eth important control board manipulations and operation of
equipment in the field (Section 05.1).
. The simulator was upgraded for modifications which were in the process
- . of being. installed in.the plant. Simulator training-could result in _
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misinformation to the operating staff if significant. changes.were -
required during modification installation or testing'(Section 05.2).
- . The licensee's corrective action program, as implemented by the PC
process, was considered to have significant weaknesses at the time of
the inspection (Section 07.1).
. A positive observation was identified for the effectiveness of the self-
assessments in identifying deficient conditions (Section 07.2).
. A negative observation was noted with the implementation of the PC
- . agram for not properly identifying deficient conditions (Section
07.2).
. A weakness was identified for down grading Quality Program audii. and
surveillance findings contrary to procedure CP-]11 program guidance
(Section 07.3).
. A weakness was identified for a lack of guidance in procedure CP-111 for
ensuring Quality Program management concurrence when down grading
Quality Assurance (QA) findings and for ensuring a 30 day response for
QA findings (Sectica 07.3). ,
.
. A negative observation was identified for a lack of traimng in the area
of root cause for Quality Program Department personnel (Section 07.3).
Maintenance
. A maintenance weakness was identified for not adequately maintaining tha
heat trace system and inappropriately voiding work requests (Section
02.1).
. A negative observation was identified for not 3roviding identification
tags for the Borated Water Storage Tank and Maceup Tank level
transmitters (Section M2.1).
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e 0
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o A corrective action violation was identified for failing to install stem
protectors on valve MUV-58 and MUV-73 act"ators when the condition was
identified in March 1996 (Secticn M2.1).
. A weakness was identified in the licensee's self-assessment process, in ,
that, resolution of PC 97-3449 failed to characterize the scope of the
deficiencies with thread engagements on High Pressure Injection Valves
MUV-23, 24, 25 and 26 adequately (Section M2.1).
. ' Material condition of the makeup and purification and decay heat removal
systems in the auxiliary building was generally adequate. Material
condition and housekeeping in the reactor building were judged as poor
(Section M2.1).
. A positive observation was identified relating to the periodic and
. predictive maintenance activities for the makeup and purification and .
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-decay heat removal systems. Maintenance activities were: adequate to
identify and resolve equipment degradation issues (Section M2.2).
- . A positive observation was noted during review of the licensee's
equipment history for key system components. Maintenance activities
were adequate to identify repetitive maintenance and equipment failures ,
and initiate appropriate corrective maintenance for the equipment
failures (Section M2.3).
. An open item was identified to ensure that all required ASME Section XI
valve testing would be completed as required (Section M2.4).
. A weakness was identified for not identifying all valve testing as
needed to meet the ASME Section XI program (Section M2.4).
. A negative observation was luentified for the marginal valve stroke
acceptance criteria for MUV-257 (Section M2.4).
. A weakness was identified for not performing vibration monitoririg of the
Decay Heat Closed Cycle P.;iing System pump motor cooling fans (Section
M2.5).
. A violation was identified for failure to test 'high pressure injection
valve MUV- 23, 24. 25. and 26 power selector switches adequately
(Section M2.6).
. A negative observation was noted in that procedural guidance was
inconsistent in providing direction for backfilling/ draining level
instrument reference legs (bection M2.7).
. A violation was identified for failure to provide an adequate procedure
for calibration of reactor vessel level instrumentation for reduced
inventory operation (Section M2.7).
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. Weaknesses were noted for a arecursor card associated with SP-195 in
that it failed to identify t1e inappropriate procedural guidance, failed
to identify the inoperable condition of the r? actor vessel level
instruments. and provided inappropriate recommendations to stop taking
as-found data (Section M2.7).
. In general, procedures for complex mechanical maintenance activities for
the makeup and purification and decay heat removal systems provided
adequately detailed instructions. The procedures included appropriate
technical criteria. Quality Control (OC) hold points and OC involvement
were adequate. Documentation of completed work was good (Section M3.1).
.
A violation was identified for failure to evaluate out-of-tolerance
Measuring & Test Equipment (M&TE) (Section M3.2),
, - . The program for. control of. portable M&TE maintained byythe calibration -
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laboratory was good (Section M3,2). m.- -
- Procurement documentation for c sample of installed makeup and
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purification and decay heat removal systems' equipment demonstrated the
implementation of appropriate technical and quality requirements in the
procurement process (Section M3.3).
. A violation was identified for failure to follow foreign material
exclusion procedure requirements (Section M4.1).
- A weakness was identified for inconsistent procedural guidance provided
by the-foreign material exclusion program procedure CP-116A (Section
M4.1).
. The licensee adequately identified and prioritized the maintenance
backlog for the makeup and p -ification and decay heat removal systems
as a function of the system headiness Review Process (Section M7.1).
Engineerina
. The liter.ae's drawing control program, for control room critical
drawings, was adequate (Section E1.1). .
. An unresolved item was identified for NRC evaluation of the
acceptability of thermal expansion chambers for containment penetration
line modification (Section E1.2).
. An unresolved item was identified for NRC evaluation of the
acceptability of the makeup system trains crosstied without the ability
to remotely isolate the trains (Section E1.3).
. Licensee performance in the mechanical engineering aspects of the makeup
and purification and decay heat removal systems was judged by the team
l to be acceptable (Section E1.4).
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. Licensee performance in the electrical engineering aspects of the makeup
and purification and decay heat removal systems was judged by the team
to be acce) table. However, the adequacy of electrical calculations
could not se judged at this time because corrective actions have not
been completed to update the calculations. This was identified by the
licensee as a restart issue and will be inspected by NRC as part of the
closecut of Violation B to Escalated Enforcement Action EA 96-365
(Section E1.5).
. A violation was identified for failure to assure that conditions adverse
to quality, drawing errors, were promptly identified and corrected
(Section E1.5).
. A violation was identified for overload relays not instiled as
automatic reset as stated in the Final Safety Analysis Report (Section
El.5). . . m~~
^
. LicenseeperformanceintheinstrumentationandcontNien'gineering
aspects of the makeup and purification and decay heat removal systen..
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was judged by the team to be adequate. The Modification Aparoval Record
(MAR) packages reviewed were technically adequate and were seing
implemented in accordance with the licensee's requirements and NRC
regulations. The licensee's procedures provided adequate controls for
implementation of the licensee's design control process (Section El.6).
. An unresolved item was identified for NRC review of the licensee
response to GL 88-17 associated with reduced inventory operation
(Section 2.1).
. The ASME Section XI pump testing of the decay heat removal and makeup
and purification systems was found to be acceptable (Section E2.2).
. A negative observation was identified relating to problems with
attention to detail while performing surveillance testing (Sectic
E2.2).
. A negative observation was identified for not having a pump and valve ,
trending program (Section E2.2). ,
'
. The licensee had a Probabilistic Safety Assessmer.t (PSA) model for
Crystal River Unit 3 and had changed an Emergency Operating Procedure
based on PSA information (Section E2.3).
. The Enhanced Design 9 asis Documents and the Final Safety Analysis Report
(FSAR) were adequate for the selected systems; however, one discreaancy
was noted in the FSAR regarding required operator action for a higa
, pressure injection line break small t'reak Loss of Coolant Accident
(Section E3.1).
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- A violation was identified for failure to take adequate corrective
actions to identify and correct the design weaknesses associated with
adequacy of the past 10 CFR 50.59 review for positioning of DHV-34 and
DHV-35 during normal operation (Section E4.1).
. The licensee was adequately managing open items associated with
partially installed modifications (Section E7.1).
(ieneral Observations
The following additional NRC observations were made based on overall
assen ments spanning all functional areas reviewed:
. Communications between licensee representatives and NRC inspectors were
,
good during the irspection period.
~
- * . System Readiness Reviews were judged to be of good ckbliiy,_ well -
organized, and pr ovided an appropriate barrier for assurance that
restart issues were being addressed.
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- System Engineer's knowledge of the of the decay heat removal and makeup
and purification systems was judged to be good.
- Licensee sensitivity to initiation of precursor cards for identified
issues was good.
The team assessed the licensee's performance in the five areas of continuing
NRC concern in the following se-tions: the assessments are limited to the
specific issues addressed in the respective sections.
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NRC AREA 0F CONCERN ASSESSMENT SECTION
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OPERATIONS MAINTENANCE ENGINEERING OUALITY
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ASSURANCE
tianagement Oversight A A A A
Engineering Effectiveness A , A A
KnpyledgeofDesignBasis G A A
Compliance With Regulatmns A A A A
k+rator Perfoma^ A
5 - SuperwT aod A= Adequate /fcceptable I = Inadequate
Blant - N ted/ Insufficient Information
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Report Details
Summary of Plant Status
Crystal River Unit 3 was shutdown with Reactor Coolant System temperature
below 200* Fahrenheit during the inspection period.
Introduction
The primary ubjective of this inspection was to assess the operational
aerformance capability of the makeup and puri/ication system and the decay
leat removal system through an in-depth, multi disciplinary engineering review
) to verify that the selected systems were capable of performing their intended
safety functions. Generic safety significant fincings were pursued across the
system boundaries on a plant-wide basis.
The secondary objective of this inspection was to determine the program-
.. related root cause for identified performance- deficienci6s-and-to . analyze the. .
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implications- of -these deficiencies on the licensee's quality assurance ,
program. -
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The licensee provided an overview presentation of the operational readiness of
the makeup and purification system and the decay heat removal system on
October 6. 1997. Overview handouts are included as Attachments 1 and 2 of
this report.
I. OPERATIONS
02 Operational Status of Facilitks and Equipment
02.1 Heat Trace System Deficiencin
a. Scoce (71707 and 93801)
The team observed the operation of various support systems while walking
down the decay heat removal and makeup and purification systems. As
part of this review, team members observed the operation of the heat
trace system which is used to ensure that the various system boric acid
concentrations rema'n in solution.
b. Observations and Findinas
'
During the walkdowns of the decay heat removal system and the makeu) and
purification system. the team noted that- various heat trace panels lad
multiple alarms with potentially out of tolerance indications. A
detailed review of the individual panels and circuits was initiated.
The inspection included a review of the operator logs and related system
surveillances. The heat trace system was considered to be imp 1rtant
because, among other functions, it maintained the temperature ror the
emergency boration flowpaths.
During the reviews and walkdowns. the team noted several problems with
the operation and maintenance of the heat trace systems. The problems
and deficiencies are detailed in the following paragraphs.
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a
- Heat trace control panel. HTCP-1 was found with multiple alarms. The
. panel contained 28 circuits and supplied heat trace for the reactor
j coolant evaporator and waste evaporator systems. The team noted that ,
four circuits weie in alarm for under-temperature. seventeen circuits
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were in alarm for over-temperature, and four circuits had circuit i
failure alarms. Discussions with the licensee determined that the
, evaporators had been in a long term program for abandonent: however.
l the program had not been completed. The licensee stated that the .
i equipment was not being monitored by o)erations or maintenance.
!' 'Following discussions with the team, tle licensee said the equipment
4 would be shutdown as appropriate. . The team notea a negative observation
, in not actively monitoring operating plant equipment.
1
Daily rounds and two routine surveillances were performed on circuits in
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HT-001 TR and HT-002-TR. Circuits 2. 3. 6. 7, 9, 10. 12 and 13 on
!
. . . .HT-001-TR and circuits 3, 4. 5. 6,14.15.17. and .24-on HT 002-TR were .
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monitored by each of the following surveillances: ProcedurfLSP 301.- -- L
i Auxiliary Building Shutdown Log Readings: Procedure SP 306. Weekly
l Surve1' lance: and Procedure SP-320, Availability of Boron injection
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Sources and Pumps. The team noted that each surveillance listed a
j different acceptance criteria for temperature. For example: Procedure
! SP-306 listed an acceptable band of 140-190 degrees F: Procedure SP-320
noted that temperatures were required to be above 105 degrees F: and
Procedure SP-301 noted that the minimum and maximum temperatures should
l be normal with no values provided. Also, the panel data plates listed a
j low temperature alarm at 152 degrees F and a high tempereture at 169
- degrees F. The lack of consistent guidance in the surveillances was
J. considered to be a weakness.
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The team noted that the data documented for circuits 12 and 13 in
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Procedure SP-320. Availability of Boron Injection Sources and Pumps, was
! in error. The completed surveillance. dated September 17, 1997.
! documented that circuit 12 was *0 pen ~ and circuit 13 was at 81.5 degrees
.
F. However, the team noted that circuit 13 was "Open' and circuit 12
I was at approximately 81 degrees F. This was also confirmed by data
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. documented in Procedure SP-306. Weekly Surveillance Log, dated
- October 4. 1997. The error in documenting required surveillance data
{ was considered to be a weakness. ,
1
. Heat trace panels. HT-001-TR and HT-002-TR were observed to have
l various deficiencies such as over temperature alarms, open circuits.
L under-temperature alarms and open work requests. These Janels pruvide
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monitoring of the heat trace circuits for the emergency ) oration
flowpaths.
,
- The team reviewed the operation of heat trace panels HT-005. 006. 007,
4 and 008. The team noted that multiple circuits were in alarm with no
deficiency tags, circuits that were to be monitored by the daily
- surveillance logs were not recording, circuits were recording that were
j not monitored, and some heat trace panels listed circuits as " spare":
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however. the panel was recording a value for the spare circuit. A
weakness was identified for not promptly identifying the deficient
conditions of the heat trace system.
The team noted that the daily logs documented in SP-301 were deficient
because of lack of clear guidance The logs required the operator to
check the operation of the eight heat trace recorder panels. However,
the special instructions for the logs directed the operator to only
verify the recorders had paper and were inking. The lack of guidance in
the operator logs was considered to be a weakness.
During and following the system walkdowns, the team discussed with the
licensee, the deficient conditions of the heat trace system, In
response to the team's concerns, the licensee initiated a Precursor Card
(PC) 97-6942. which documented the observed problems with the heat trace
system. PC 97 6942 noted that "a review of the procedures and heat
trace recorders revealed numerous problems... numerous heat trace points
that are out of tolerance and in alarm with no associated work request
generated" and "It is apparent that the system is not being properly
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attended by the operators." The " Apparent Cause" section noted that
" Operators have written many work requests over the years without any
long term success. Many of the work requests have been voided or
canceled. There have been many repeat maintenance work requests." and.
"A review of work request history associated with the system shows a
long history of hundreds of work requests." The PC also noted that "The
operators have become inattentive toward the system due to a long
standing problem with maintenance of the system. The recorders are
nearly constantly in alarm due to drifting of the heat trace
controllers."
The teams also noted that the associated heat trace system control room
alarms on the sequence of events recorder, were disabled in 1994 due to
being nuisance alarms.
c. Conclusions
The following conclusions were reached regarding heat trace systems for
piping containing boric acid water: ,
. A negative observation was noted for not actively monitoring
operating plant equipment.
. A weakness was identified due to a lack of consistent guidance in
operator surveillance activities and lack of guidance in operator
logs.
- A weakness was identified for an error in documenting required
surveillance data.
- An operation's weakness was identified for not continuing to
identify deficient conditions on the heat trace system and
disabling related control room alarms.
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- A maintenance weakness was ideritified for not adequately
maintaining the heat trace system and inappropriately voiding work
requests.
03 Operations Procedures and Documentation
03.1 Doeratina And Alarm Procedures
a. Insnection Stone (71707. 93801)
The team reviewed System Operating Procedures (0P) 402. " Makeup and
Purification System, Revision 94" and OP 404 " Decay Heat Removal System.
Revision 109". The review included comparisons with the applicable
sections of the FSAR and the enhanced design basis documents and
included discussions with and simulated procedure performance by
_ licensed operators. In addition.. ten alarm procedures:were reviewed. .
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.. . .
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b. Observations and Findinos:
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Changes to OP-402 for the makeup and purification system and OP-404 for
the decay heat removal system were still being identified during this
inspection period. In some instances, the need to revise the procedures
resulted from Modification Approval Records (MARS) which might impact
the procedure but the specific changes, if any, had not been developed.
Identified pending changes were to incorporate operator suggestions,
correct errors, delete unnecessary information, and provide additional
detail. For examale, the number of NUPOST items for OP-402, last
revised on Septem3er 14. 1997, had increased from 14 on October 9. to 22
on October 22. 1997. NUPOST was the licensee's computerized system for
tracking outstanding procedure changes. One NUPOST item could involve
multiple comments and or changes to a procedure. Likewise, the NUPOST
items for OP-404 had increased from 9 on October 9. to 14 on October 22.
1997. A draft OP-404 revision had 44 identified changes incorporated
into the procedure. Due to the large number of ongoing changes to these
procedures, it was not possible to determine adequacy of these
procedures. Due to the large number of changes already made and
pending, the team concluded that any results by the licensee's system
readiness review concerning the adequacy of OP ,402 was no longer valid.
An Inspection Followup Item. (50 302/97 14 01). was identified fcr
Review of Operational Procedures Prior to Restart.
Several observations were made concerning the procedures. In general,
human factor considerations were poor. For example, in some instances
important operator actions were contained in cautions and notes while in
other instances similar actions would be contained in steps requiring
operator signoffs. Also, some sections of the procedures were task
'
oriented. i .e. . steps included operation of redundant equipment. thereby
requiring the operator to mark numerous steps as not applicable;
whereas. Other procedure sections were equipment oriented, i .e. , the
task was written around one major component such as a pump, and other
procedural sections would address the sar'e task for redundant equipment.
The team also noted that a writer's guide. Administrative Instruction
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(AI) 4028. " Procedure Writ.1ng (Except For Abnormal Procedures. Emergency
Operating Procedures (EOPs) and Test Procedures)". defined new rules and
format for these Operating Procedures (ops), but the existing ops had
been " grand fathered' such that only the step being revised need follow
revision 16 or subsequent revisions of the writer's guide. Furthermore,
the team noted that the definitions in the verb list for the operating
3rocedures varied somewhat from that provided for the same word in the
E0P procedure writer's guide verb list. Usually the operating procedure
definitions were broader in scope or more general in nature than those
for the E0P procedures, The licensee issued PC 97-6910 to determine the
feasibility and need for an operating procedure upgrade project.
Examples of specific problems noted with the operating procedures
included:
. . - * Step 4.2.12 in OP 402 for testing the Makeup Pump.(MUP) backup .
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gear oil pump would-not verify that this pump would . auto-start if-.
necessary since the main gear oil pump was started in a previous
step. In addition, the step did not identify to the operator that
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the shaft driven gear oil pump may be faulty and the MVP may need
to be secured if the main gear oil pump did not shutdown in 2
minutes after the MUP 1s started.
- Step 4.5.7 opened the pressurizer auxiliary spray valve DHV-91, a
containment isolation valve. prior to placing either decay heat
removal train A or train B in service. However. the subsequent
valve alignment provided a spray flowpath only from train A.
Providing spray from the B train was an abnormal configuration
addressed in the E0Ps. The team considered that opening a
containment isolation valve when not required was undesirabie
An operator simulated steps in OP-402, Sect!ca 4.17. to re-align the
)ower source for the B MUP from the A train to the B train. A set of
ceys with colored tags were used to lock and unlock electrical breakers
j to allow operators to switch the power source while preventing the
electrical trains from being cross connected. The team noted that
neither the red nor the green key was in the Shift Supervisor On Duty
- (S500) key locker as specified by in the procequre
- however, a yellow
l key without a number was in the S$0D key locker. Both the red and green
! keys were found in the breaker locks. The yell.ow key was subsequently
l verified as a key that should always have been in a breaker lock, i.e. .
l never in the SS00 key locker. The team also noted that the red key was
l actually white with red lettering, whereas all the yellow, blue, and
green key tags were the specified solid color. The yellow had no number
because the corner of the tag with its identifying number had been
broken off. The procedure made reference to the keys only by color, not
by identifying numbers. The team also observed that the inventory list
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kept with the SSOD key locker provided a number and description such as
" KEY 38 MUP 1B A SIDE CAPTIVE KEY." but no reference to its color. Not
providing a consistent identification for and maintaining the proper
location of the B MUP breaker lock keys were considerad as a weakness.
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- During a simulated walkdown of portions of OP 402 with a licensed
4 operator, the team noted that Makeup Tank level and pressure chart
!_ recorder (MU 014 LIR1) label on the main control board was not color
j coded to show which ink trace. the red or green, went with the-level and
j pressure pen. The licensee immediately corrected this problem.
i
j The alarm response procedures-reviewed were adequate. Alarm procedures
! were available for each annunciator window and provided redundant _
l '
indications to verify if an alarm was valid. Operator actions for valid
l alarms were typically superficial actions such as investigate the cause
- of the condition or ensure that a given action had occurred. The '
- DISCUSSION section of the alarm procedure might provide additional
i actions or reference applicable operating procedures'or instructions to
j enter. l
i
!. . . . Minor differences were noted between the descriptiventext.provided in .
i -
- quotes in the operating procedures and the title engraved;on the - .
!
annunciator window. For exam]le, in OP 402 an annunciator window was
! described as "MUP LUBE OIL PRESSURE LOW" but the actual annunciator ,
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! window read " MAKEUP PP C LUBE OlL PRESS LOW."
c. Conclusions
l
The adequacy of the system o)erating procedures for the Makeup and
l Purification System and the )ecay Heat Removal System could not be
j determined due to the large number and types of changes pending. An
- Inspection Followup Item was identified to review the adequacy of these
- procedures. !
h A weakness was identified for not providing a consistent . identification
- for and maintaining the proper location of the B Makeup Pump breaker
i lock keys.
The alarm response procedures reviewed were adequate. Operator-actions
1- for valid alarms were typically superficial actions.
! 03.2 Procedure Chanae Error ;
4 .
l-
a, Insnection Stone (71707. 93801)
The team reviewed the circumstances surrounding'an improper
]
- implementation of a Plant Review Committee recommendation,
i
i b. Observations and Findinos
I While reviewing reasons for previous changes to OP-404, the team
i discovered that Revision 109, a minor change, was approved to correct an
j error-in Revision 108. When the Plant Review Committee disapproved '
!
incorporating ste)s to open and de energize ACIS valves DHV 3. DHV-4.
- and DHV-41, into Revision 108. only two of the four new steps were 3
4 deleted. i.e. two steps disapproved by the Plant Review Committee were
, incorporated into the procedure. The Plant Review Committee disapproved
I
1
i
d
i __ _.___... ,___ ~,_, ... _ ,., _ _. _ _ _ _ ,. _ _ . _ - _ _ _ _ . . _ _ , _ _ . , , . _ _ _ . _ . _ _
_ _ _ _ _ __ __
. .
7
the steps until the change could be researched more thuroughly to verify
no commitments to the NRC were being impacted. A licensed operator
discovered the problem and Revision 109 was issued to delete the
unwanted steps. The ]roblem was attributed to the normally assigned
procedure writer not )eing available at the time the Plant Review
Committee recommendation was incorporated into Revision 108. Subsequent
engineering reviews determined that the ACIS could be defeated: however.
a different method was more desirable. The team was informed that no PC
was written concerning the event. The team discussed the issue of
incorporating steps into procedures which had been disapproved by the
Plant Review Committee with licensee management. After this discussion,
the licensee issued PC 97-7252 to address this event.
c. Conclusions
- . A weakness in the. licensee self-assessment program wassidentified for
- -
not issuing a Precursor Card.(PCF when the licensee discovered that a
procedure change. recommended by the Plant Review Committee to be
deleted from a proposed procedure revision. was incorporated into the
-
revised procedure.
04 Operator Knowledge and Performance
04.1 Doerator Knowledae (93801)
a. The team evaluated operator knowledge of the makeup and purification
system and the decay heat removal system by conducting discussions with
both licensed reactor operators and senior reactor operators.
b. Observations and Findinas
The team evaluated operator's knowledge of the selected systems by
comparing information from operators as performance of OP-402 and OP-404
sections were simulated. and from the alarm response procedure
discussions to the information contained in:
. the pre res' precautions and limits sections.
. the Enhanced Design Basis Document for th'e systems.
. the systems' design basis described in Ch' apter 6 of the FSAR and
- the replacement operator training lesson plans for the systems.
The team judged that operator knowledge was good in the areas of normal
and abnormal system operating configurations, equipment interlocks.
setpoint bases, and system and equipment precautions and limits.
c. Conclusions
Operator knowledge and understanding of the Makeup and Purification
System and Decay Heat Removal System operations were good.
-_ -_____- -- _ _
. .
8
04.2 Ooerator Performance
a. Insoection scoDe (71707; 93801)-
'
The team judged operator performance by observation of activities in the
control room, during simulated procedure usage, and accompanying
operators while gathering log data and performing equipment checks.
,
b. Observations and findinas
Control room activities were observed to be conducted in an overall good
manner. The operating staff limited assess to the control area and
communicated among themselves formally by using repeat backs during
important conversations. Especially noteworthy was the control board
operators' immediate response and acknowledgement of plant alarms.
. - .- . . .
m. m . .
- - -
- Excluding the problems associated with heat trace circuits: discussed in
Section 02.1. operators recorded log readings as required and observed
equipment checks performed were thorough. The team requested
o information concerning what guidance was available to provide
management's expectations for performing equipment checks. Operating
Instruction (01)-02. " Shift Routines and Operating Practices." Revision
2. required tours to identify degraded conditions that may require
operability determinations and to monitor the condition of all eguipment
in the assigned areas. 01-07. " Control of Equipment and System.
Revision 6. stated that Operations role is to conduct comprehensive
walkdowns and inspections to identify deficiencies in plant structures,
systems and components. Interviewed Operations personnel indicated that
on-the job training was the primary means by which operators were taught
what constitutes a comprehensive walkdown. The team noted some
differences among operations personnel as how frequently some checks
associated with safety related and important to safety equi) ment were
performed. For example, operators varied between every waltdown to
every few days as to how often oil levels in non-operating Nuclear
Service And Decay Heat Seawater System (RW) pumps were checked. Not
providing specific written guidance as to management's expectations for
the conduct of equipment checks was judged to be a weakness.
Theteamobservedoperatorsperformingdatacoflectionwithahandheld
data logger. Entered data was sampled to verified that values had been
correctly entered. No discrepancies were found. In addition, a
printout of collected logs was compared with SP 300. " Operating Daily
Surveillance Log.' Revision 139. A random sampling revealed no
differences between the data's frequency and acceptance criteria between
these documents. An operator was asked how Technical Specification (TS)
required daily channels checks were performed, for example on Reactor
Protection System Reactor Coolant System pressure instruments, when the
hand held data loggers were not available. The operator thought that
these channel checks were in a procedure, but he was unable to locate
the applicable procedure steps. The team was later shown that the
information was contained in Enclosure 9 to SP-300.
..
. . .
.
. . . . .r. . . .. ..
_
. _ . _
, .
9
'
c. Ceclusions
Control room activities were observed to be conducted in an overall good
manner. During plant tours. operators were recording log readings and
equipment checks as required. However, a lack of specific written
guidance as to management's expectations for the conduct of equipment
checks was a weakness.
05 Operator Training and Qualification
05.1 Doerator Trainina and Job Performance Measures (JPMs)
a. Insoection Scone (93801)
The team reviewed Replacement Operator Training lessons (ROT) 4-52.
.,
" Makeup and Purification System.". Revision 11. and ROT-4-54. " Decay Heat -
- - - 4
Removal." Revision 10. against OP-402.and OP 404 and the. enhanced design -
basis documents for the systems. Ten JPMs. numbers 020, 037. 046. 077.
102. 132. 171, 173, 174 and 175, involving the two systems were also
- reviewed,
b. Qbservations and Findinas
The comparison of selected information among the lessons, the system
o)erating procedures and the enhanced design basis documents revealed
t1at these documents were generally consistent with one another. An
example was found in which ROT 4-54 had not been revised when a limit
and precaution in OP 404 was revised. Specifically the lesson stated
that to prevent exceeding the decay heat pump's 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> mission time,
flow must be increased above 1400 gallons per minute (gpm). The revised
limit and precaution allowed operation for up to a year with flow
between 100 and 1200 gpm. A PC was issued to address this
inconsistence.
The team was also provided a list of 25 MARS which as of September 22.
1997, were authorized to be installed prior to unit restart: however,
sufficient information had not been provided to training to allow
training needs to be identified. ,
Although there were some minor wording differences between the JPMs and
the similar steps contained in the system operating procedures, the
content and flow of actions were basically the same. The team noted
that JPM 046 and 173 covered the same task and the initiating cue for
these JPMs was not worded well. These JPMs directed the operator to
transfer the HPl (makeup) pump surtion from the BWST to low pressure
injection after the Emergency Core Cooling System (ECCS) pump suctions
have been swap)ed to the reactor building sump. However. if the ECCS
pump suctions lad been aligned to the reactor building sump, the
emergency operating procedures would have already aligned the running'
makeup pump to the low pressure injection pump before the low pressure
injection pump was realigned. These observations were discussed with
.
. .
i 10
5
the training supervisor. The team was informed that prior to use. JPMs
were compared with the applicable procedure steps to ensure the JPM
- accurately reflected the task to be performed,
c. Conclusions
The Makeup and Purification System and Decay Heat Removal System
- Replacement Operator Training lessons were generally-consistent with
- system operating 3rocedures and the enhanced design basis documents for
i 'these systems. Tie Job Performance Measures were adequate to
j familiarize operating personnel with important control board
i manipulations and operation of equipment in the field.
! 05.2 Simulator Observations
}; a.. Insoection Stone (93801) . . . ,.
-
.
- . . ~
l TheteamcomparedinstrumentationandcontrolsonthemaiUontrolboard
i with those on the simulator's control board.
-
! b. Observations and findinos
j The team noted that several plant modifications which had not been
4
installed in the plant were functional on the simulator's control bosrd.
. and operators were already being trained on this equipment. Changes
! included: addition of control switches for the new HPl recirculation-
line valves and for the new containment isolation valve MUV 567, and ES
- status lights added for MUV 567 and deleted for MUV-505C. The team
i expressed concern to management that providing training on modifications
- - that were not installed iri the plant could result in misinformation if
,
significant changes were required during installation or testing. In
! addition, these observations were discussed with NRC personnel who have
! been selected as team members for the review of emergency operating ~
! . procedures.
! c. Conclusions
1
i The simulator was upgraded for modifications which were in the process
i of being installed in the plant. Simulator training could result in
- misinformation to the operating staff if signif.icant changes were
- required during modification installation or testing.
07 Quality Assurance in Operations
- 07.1 Corrective Action Proaram
I
a. Insnection Scope (93801)
-
The team-reviewed and observed activities related to implementation of
4
the corrective action program as implemented by the precursor card
system.
1
I
4
.
4
.-e-t- , , , -,--,,wev--v-.v,wv-- , , - - , , , - , - , , - , , - - , - - - , , - - . , y- -----my,+.,... , 4.~--, . - .w.,
_ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. .
11
b. Observations _and findinas
During the inspection, the team observed various mectings related to the
corrective action progrcm and discussed multiple items documented in the
corrective action program. The discussions with the licensee indicated
that the program had undergone significant revisions in September and
October 1997 to address various program weaknesses.
The team observed the " Precursor Review Meeting" and noted that the
committee reviewed 41 items.in about 50 minutes. The team noted that it
was hard to follow which PC was being reviewed. Several times during
the meeting. committee members asked which PC was under review although
discussion had been taking place on a specific PC. In addition, the
team noted that the meeting appeared to be only a clearing house for
assigning responsibility for addressing the PC. The members did not
. discuss any guidance to be.used by the assigned organizat, ion for .
- -
adequately resolving the issue or, specific areas to be covered in the -
response.
-
The team observed a " Plant Review Committee" meeting and noted some
discussion of various PC issues. The meeting did not provide for
detailed discussions of the issues: however, the discussions were more
detailed than those in the Precursor Review Meeting.
The team discussed with the licensee the number of "B" level PCs and
noted that only approximately 190 "B" level PCs had been generated in
1997 out of approximately 7200 PCs. This a)peared to be a low number of
"B" level PCs. Further review determined tlat the licensee did not have
a functioning program for identifying recurring PCs. and therefore, few
trending PCs had been generated during the year. A new trending
software program had been purchased and the corrective action program
was revised in the first week of October 1997 to identify trending PCs.
At the time of the inspection. it was still too early to evaluate the
effectiveness of the new trending program.
The team reviewed Quality Programs Surveillance Report. 97-0129.
completed on September 22. 1997. The surveillance reviewed 2046 PCs
generated from January through May of 1997. Th,e report noted the
following:
. Of the 2046 PCs generated. 284 had still not been assigned for
resolution. The PC program procedure required the identification
of corrective actions within 30 days.
. Of the 1762 PCs assigned. the responsible department or individual
had not responded with the proposed corrective actions for 296 of
the PCs.
. Of the 747 "C" level PCs. where there were proposed corrective
actions and the PCs had been closed based on commitments to
implement the corrective actions. the surveillance noted that for
approximately 500 of those "C" level PCs. there was no evidence to
__ __ __
. .
12
show that the corrective actions were ever implemented. During
the inspection the licensee was considering reopening the 500 PCs.
. There were 1237 'D" level PCs identified during the assessment <
period. The team noted that the program in place for these PCs
did not require any response to identify corrective actions or any
documentation to provide closure.
The team noted that the licensee had recently revised their corrective
action program to address many of the above concerns. Due to the recent
revisions, the team was unable to evaluate the effectiveness of the new
program. Based on the review from the first six months of 1997, the
team concluded that the program was not effective in resolving minor
equipment and personnel deficiencies.
c. Conclusions -. .
. . . ._ - ..
The licensee's corrective action program, as im)lemented by the PC
process, was considered to have significant weacnesses at the time of
-
the inspection.
07.2 Li_qensee Self-Assessment Activities
a. Inspection Scoce (93801 and 40500)
The team reviewed various licensee self-assessments to determine the
effectiveness of the licensee's self-assessment programs.
b. Observations and Findinas
After reviewing various operations. maintenance and surveillance
activities, the team reviewed related licensee self-assessments to
identify differences in observations and to evaluate the effectiveness
of the licensee's self-assessments.
The team reviewed the self-assessment for the In-service Testing
Program, dated October 15, 1997. The assessment report identified the
following weaknesses: ,
. Some motor operated valves were not being. properly stroke tested.
,
. Several containment isolation check valves were not being closure
tested.
. No procedural guidance for establishing stroke reference values
and limiting values.
. There were instances of improper installation of flow instruments
that led to inaccuracies beyond Code Allowances.
_ _ _ . . . _ _ .
. .
13
. There was an improper test of the main steam isolation valves
(MSIVs) due to using a non-credited air supply during testing to
assist closure.
. Operations department functional understanding of in-service Test
(IST) requirements was lacking.
. Valve stroke test data trending was not performed at an industry
accepted standard.
. There was r.o procedural requirement tn notify the IST group when
gauges used in IST tests are found out of calibration.
The team discussed the missing valve testing with the licensee and noted
the licensee's corrective actions. This issue was documented in Section
M2.4 of this report. In that section, the team noted-additional valve
-
testing that had not been-identified daring the self-assessment. Based
on the number and type of findings identified in the licensee's self-
assessment, the team concluded that the self-assessment was effective in
-
identifying deficiencies in the In-service testing program.
The team reviewed PC 97 6844 which was initiated on October 1. 1997. for
the missing valve testing. The PC noted that. "The fact that these
tests were not previously credited in the IST Pr^ gram is not a condition
adverse to quality." and, this PC was graded at a level which required
no respnose, in the recently revised corrective action program. The
team noted that the " Condition" writeup was misleading since the failure
to adequately test the various motor operated valves was a condition
adverse to quality, resulting in an improper grading. The team also
noted that the licensee had not initiated a PC for the finding that.
,
" Operations department functional understanding of the IST requirements
is lacking."
'
The team reviewed the self-assessment for Operations. dated
'
September 23, 1997. The assessment report identified the following
weaknesses:
. Assessments were not being effectively ut,ilized.
. Assessment and precursor data was not being evaluated to determine
the specific causes of poor performance.
. Common cause analysis data provided from precursor root causes has
not been promulgated or utilized.
. Understanding and buy-in to some elements of procedural compliance
was lacking.
. Some operators displayed a lack of knowledge of valve position
verification requirements.
i .
14
. Equipment deficiencies were not consistently reported and
documented.
- Increased attention was needed to ensure concerns raised by
operators are fully and properly evaluated by supervisors.
Additional strengths and weaknesses were identified in the self-
assessment. Based on the number and type of findings identified in the
licensee's self assessment. tt e team concluded that the self-assessment
was effective in identifying deficiencies in the operations area.
c. Cgnglusions
A positive observation was identified for the effectiveness of the self-
assessments in identifying deficient conditions.
, . ..
_
-
A negative observation was noted with the implementation of_ the PC. . .
program for not properly identifying deficient conditions
- 07.3 Effectiveness of the Quality Proarams Oraanization
a. Insnection Scone (93801 and 40500)
The team reviewed various licensee Quality Programs audits and
assessments, to determine the effectiveness of the licensee's quality
assurance program.
b. Observatio,s and Findinas
The team reviewed various audits and assessments conducted by the
Quality Programs department. It'e team performed a detailed review of
Audit 97-02, dated March 17, 1997, and Audit 97-04, dated June 2. 1997.
The review noted a significant number of findings in each of the
functional areas such as operations, maintenance and engineering.
Overall, the team concluded that the licensee's audit program was
effectively identifying deficient plant , personnel, and corrective
action program conditions.
The team noted that when the Quality Programs' ' audit group identified
deficient conditions. Precursor Cards were generated to capture the
deficiencies in the corrective action program. A review of audits 97-02
and 97-04, indicated that the actual grading for the PCs generated
during the audit. was in conflict with the PC's program )rocedural
requirements. This issue was discussed in detail with t1e licensee and
the following types of issues were identified:
- PC 97-0983. noted that "CR3 has failed to take timely corrective
action to address design basis deficiencies." The quality
3rograms department recommended that this PC be graded as a "B":
lowever, the review board graded this PC as a "D"
..
_ . .
t 8
15
. PC 97 1032. noted that there was a " failure to control resolution
documentation for "C" precursor cards." The quality programs
department recommended that this PC be graded as a "B": however,
the review board graded this PC as a "C
. PC 97-2754, noted that "Results of the OA review indicated that
there is a significantly increasing trend in overdue corrective
action ste)s. It is recommended that this PC be classified as a
grade "A" Dased upon the previous corrective actions not being
effective." This PC was graded as a "B".
The team evaluated the grading of the PCs based on the procedural
guidance in Procedure CP-ll1. " Processing of Precursor Cards for
'
Corrective Action Program." It appeared to the team that various PCs
had been graded in error. For example, guidance for a level "D" PC
.
stated " Minor conditions adverse to quality that require-no.further .
-
action to evaluate how to correct the problem." PC 97 0983.was graded a
"D". but it was not clear why the licensee had not taken timely
corrective actions to address design basis deficiencies or how to
resolve the problem.
In the second example. PC 97-1032 identified a programmatic breakdown
which was later confirmed by Surveillance IRK-97-0129, which discusseo
the fact that 500 "C" level PCs had been closed without evidence of
corrective action. The grading of this PC appeared to be in error based
on the guidance in CP-lll for "C" level PCs. which stated " Adverse
conditions detected by independent or external assessors that do not
represent a significant or programmatic barrier breakdown."
Overall. the team noted several Quality Program findings that were not
always graded in accordance with the guidance in CP-lll.
The team evaluated the independence of the Cuality Assurance program.
The Quality Program was using the site corrective action program to
address corrective actions for Quality Program audit findings. There
appeared to be a problem with the independence of the Quality Programs
Department because the site was down grading Quality Program audit
findings. Further review noted that CP-lll did,not procedurally provide
a means for the Quality Program Department to address the down grading
of audit findings. The team also noted that CPelll did not provide
clear guidance on responding to Quality Program audit and surveillance
findings within 30 days as required by the Quality Assurance program.
These issues were discussed with the licensee and subsequently the
licensee initiated two PCs. PC 97-7268. recommended a revision to CP-
111 to proceduralize the concurrence of the Quality Programs Director
for down grading of any PC generated by the Quality Programs Department.
PC 97 7281 noted that programmatic improvements were needed with respect
to the 30-day response time for findings identified by 0A audits and
surveillances.
_ _ _ _ - _ _ _ _ _ _ _ _ _ - _ ____ _ _ _ _ _ _ _ _ _ __ _ _ __
. .
4
16
1
In addition. during discussions with the licensee. the team noted that
i
the majority of the Quality Programs personnel had not received
sufficient training in the area of Apparent Cause and Root Cause. This
training was provided to the plant staff that had to perform this
function: however. it was not provided to the Quality Programs
Department which had to review and evaluate the process for adequacy.
The licensee initiated a PC to address this concern. PC 97-7272 noted
4 that GA personnel should receive additional training in the area of
- ,
Apparent Cause and Root Cause.
c. Canclusions
A weakness was identified for down grading Quality Program audit and
surveillance findings contrary to CP 111 program guidance.
- . A weakness was identified for lacking guidance in CP-111-for ensuring .
-
Quality Program management concurrence when down gradingiOA findings and- .
for ensuring a 30 day response for 0A findings.
-
A negative observation was identified for a lack of training in the area
of root cause for Quality Program Deoartment personnel.
<
Team members assessed the licensee's performance relative to the
- Operations processes in four of the five areas of continuing NRC
concern:
1) Management Oversight --- Adequate
2) Engineering Effectiveness --- Not Assessed
3) Knowledge of the Design Basis --- Good
4) Compliance with Regulations --- Adequate
5) Operator Performance --- Adequate
II. MAINTENANCE
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Walkdown of Makeup and Purification System and Decay Heat Removal System
a. Insoection Scooe (62707 and 93801)
- .
Team members performed system walkdowns of the makeup and purification
system and the decay heat removal system. The system walkdowns were
performed in order to evaluate the overall material condition of the
systems and to identify any adverse conditions. Walkdowns were
conducted in the auxiliary building and the reactor building.
b. Observations and Findinos
Material condition of the equipment spaces in the auxiliary building
were generally adequate. Pictures posted at the entrance to each space
, demonstrated this was an improvement over the material conditions prior
to plant shutdown. Previous conditions of paint peeling from pipes and
- _ ~ ._ _,_ _ _.
_ _ _ _ - _ _ . _ - _ _- ________ _ _ - - - _ _ _ _ _
,
'
. .
17
{
4
equipment and evidence of rust and system leakage in the )ictures had
been cleaned and repainted. However, some deficiencies o) served
.
'
included heat trace panels left open, heat trace panels had multiple ,
alarms, minor boric acid leaks, missing identification tags on the
makeup tank (MUT) and BWST level transmitters, and missing
identification tags on instrument isolation valves. Except where noted
in other sections of this report, the deficiencies were considered to be
c
minor in nature. -The lack of identification tags on the safety related
BWST level transmitters and the 1mpT tant to safety MUT level
! transmitters were considered to be a negative observation.
! The team also identified three exam)les of thread engagement
i deficiencies on flange joints. Altlough the examples did not meet the
licensee's criteria for fastener thread engagement, they did not
'
l corgromise system pressure boundary integrity. The licensee initiated
j . . PCs.for the examples identified: PC 97-6929 and PC 97-6931. . .
, - - . . .
.
. . = . -
I On October 8. the team observed that actuators for Valves MUV-58 and
MUV-73 did not have stem protectors installed. The licensee informed
a the inspectors that this condition had previously been identified during
preventive maintenance activities in March 1996. Work requests, numbers
' 333797 and 333798. had been written at that time to correct the
condition. However, on June 4. 1996, these work requests were closed
- without installing the stem protectors. The work request cancellation
i- was attributed to an electrical maintenance supervisor's belief that '
! stem protectors could not be installed on these type actuators. The
i licensee initiated PC 97 6909 to resolve this issue. The licensee
determined that vendor drawing. D46409. indicated the valve actuators
'
- were purchased with stem protectors. The licensee then identified
i another 20 of 161 safety-related valves with actuators without stem
- protectors installed. The licensee initiated steps to correct these
deficiencies. The identification of a condition adverse to quality in
March 1996 without promptly correcting the condition is a violation of
10 CFR 50 Appendix B Criterion XVI. Corrective Action. This item is
! identified as a Violation (50 302/97 14 02). Failure to Assure that
, Conditions Adverse to Quality Are Promptly Identified and Corrected.
On October 21. the team identified that the adQptor plate to ycke
'
fasteners for High Pressure Injection Valves MUV-23, 24, 25 and 26 did
i not have full thread engagement. The licensee. issued PC 97-7279 to
i investigate this condition. The less-than full thread engagement had
- been noted during the System Readiness Review and PC 97 3449 had been
4 issued at that .ne. PC 97-3449 was still open at the time of this
i inspection. The licensee's immediate evaluation for PC 97-3449 had
i determined that the actual minimum thread engagement was 1.25 inches for
these valves which did not meet the value used in the vendor's (Copes
i Vulcan) weak link re) ort. PC 97-3449 identified that the condition did
not create a new weat link for these valves: however, the weak link
,
analysis should be revised to correct the amount of thread engagement
'
for the adaptor plate. In response to the team's observations, the
licensee determined that the actual minimum thread engagement was 9/16
.
inches for MUV-26. During the original determination, the licensee had
4
I
_. . _ _ ____ _ _ ,--
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - . ._
.
, , .
t
18
!
calculated the minimum thread engagement by subtracting field
i measurements of the length of bolt under lifting lugs and lock washers
plus the depth of threads in the adaptor plate not engaged from an
assumed 2and4inchlengthbolt.However,forMUV24and26the
- installed bolts where only 2 inches long. Thus, the minimum thread i
'
engagement determined for PC 97 3449 was.non-conservative. The team
agreed with the licensce's conclusion that the revised as-found thread
'
i
engagement was sufficient for the bolting to be operable. While
~
reviewing this issue, the licensee determined that in addition to PC 97- ;
-3449 evaluation incorrectly determining actual minimum thread '
i engagement, the evaluation failed to identify that the thread engagement
[ did not compl
Actuators (6)yyear
with Inspection,"
PM 178B " Preventive
- Revision 4.Maintenance
and that PM 1788 Of Limitorque specified ,
, incorrect thread engagement for the adaptor bolts. PC 97 7279 addresses
i these deficiencies. Furthermore. PC 97 7279 recommended that other
".. - valves covered by.PM 178B should be investigated to4etermine the extent ..
i. -
.of the condition. PC 97-7279 was recommended to be a: Level.B,-restart
i item 6E issue. Although the licensee's response to the team's .
i
observation and proposed actions was thorough, the failure to properly
1 -
characterize the condition and identify the problem with PM-178B was
, considered as a weakness in the licensee's self assessment process.
General material condition and cleanliness in the reactor building was
l evaluated as poor. The team noted rust on some supports, piping. cod
,
MOVs. and paint peeling from containment structures. In addition, the
,
containment sump area was very dirty,
f c. Conclusions
i
A negative observation was identified for r ' providing identification
-
4
tags for the BWST and MUT level transmitters.
A corrective action violation was identified for failing to install stem
} protectors on MUV-58 and MUV-73 actuators when the condition was
- identified in March 1996.
A weakness was identified in the licensee's self-assessment process, in
i that, resolution of PC 97-3449 failed to adequately characterize the
, scope of the deficiencies with thread engagements on High Pressure
l Injection Valves MUV-23, 24. 25 and 26.
Material condition of the makeup and purification and decay heat removal
systems in the auxiliary building was generally adequate. Material
. -condition and housekeeping in the reactor building were judged as poor.
- M2.2 Preventative Maintenance Reauirements for M82un and Purification System
and Decay Heat _ Removal System ComDongn_i_q
! a. Insoection Scone (93601)
The team reviewed the licensee's areventive and predictive maintenance
-
!'
i activities associated with the Mateup and Purification (MU&P) and Decay
,
6
i
!
-.__,__ _ ._ _ _ . . . - . _ - . _ _ , , - _ _ _ . ~ , . - . _ _ -
- -
.
!
.
!
19 l
Heat Removal (DH) systems' key components- These components include i
pumps, motors. control valves, pneumatic valves, heat exchangers, and i
instrumentation. Applicable regulatory requirements included 10 CFR 50 ,
Appendix B and the licensee's Quality Assurance (0A) program.
l
b. Observations and-Findinas
l Periodic maintenance (PM) for system pumas and motors exceeded the
-
vendor manual recommended maintenance. Review of the PM schedule and
performance documentation indicated that PM tasks were performed in the
i specified frequency. The licensee had a well developed program for ,
i predictive c.:ntenance which included vibration and oil analysis of
- rotating equipment and thermography of- electrical equipment. Quarterly
!- performance reports identified equipment requiring increased observation
] or actions to address a degraded condition. In particular, hi
- . .
vibration indications on the makeup pumps resulted in actions gh
to balance
,
or replace rotating elements in the previous two years o .
r .
, c. Conclusions ?
.
! A positive observation was identified relating to the periodic and :
} predictive maintenance activities for the makeup and purification and
! decay heat removal systems. Maint? nance activities were adequate to
j identify and resolve equipment degradation issues.
< .
- M2.3 Maintenance History Reviews
i
a. .lnsoection Stone (93801)
l-
l The team reviewed the equipment history for key system equipment to
- identify repetitive maintenance problems and resolutions. Applicable
{ regulatory requirements included 10 CFR 50 Appendix B and the licensee's
! Quality Assurance (0A) program.
s
l b. Observations and Foldinas
! A frequent seal leakage problem with the DH pumps was resolved after a r
i root cause analysis identified that the seal installation methodology :
'
contributed to installation errors. The applicable maintenance
f
'
procedure; MP-131A. " Maintenance of Decay Heat Punps." Revision 6, was
revised and there Ns been no additional Dh pump seal leak occurrences
since 1992. A repetitive valve seat leakage problem with Gate Valve
! MUV-103 was resolved during the present outage by a modification to
! install a dif ferent valve type for this function. Recent maintenanca
j activities have focused on resolving MUSP pump vibration problems. the
!
rotating element in MU&P pump 1 A was replaced in 1996 and will be
replace'J again arior to restart due to continuing vibration concerns.
i System heat exc1 angers subject to fouling (open system heat exchangers)'
i were appropriately monitored, cleaned and maintained. An initial team
- concern with the lack of inspections and cleaning of the DH heat ,
' -
oxchangers was resolved by review of the closed system chemistry
.
$
1
l-
L. _ - , _ _ , _ _ _ _ _ _ , _ . _ . _ . _ _ . _ _ _ _ . , . _ _ , _ . _ . _ . _ _ _ _ . _ ,
. _ . . _ _ . _ _ _ _ _ _ _ _ _ . . . _ . _ _ _ _ _ . _ _ _ _ _ _
, .
,
4
,
20
i
I
control. Generic Letter 8913 recomendations indicated that periodic
inspections and tests were not necessary if adequate chemistry control
4
was maintained for closed systems.
'
j c. Conclusions
A positive observation was noted during review of the licensee's
- equipment history for key system components. Maintenance activities
were adequate to identify repetitive maintenance and equipment failures
~and initiate appropriate corrective maintenance for the equipment
failures. <
H2.4 Review of in service Testina of Valves
, a. Inspection Scone (61726 and 93801)
~;. . . . .. .r . .. & .
. ... .
-
The team reviewed the program for. Stroke testing of motor _and air .
- operated valves, setpoint testing of relief valves and flow
t testing / disassembly performed on check valves for the decay heat removal
j
o and the makeup and purification systems,
l b. Observations and Findinas
! The team reviewed selected system drawings and the licensee's ASME
Section XI valve testing program to ensure that valves were tested as
required. During discussions with the licensee. the team was informed
- that various valve tests were being added to the third-10 year interval.
- The licensee stated that following a meeting in January 1996, with the
NRC in Atlanta, the licensee identified that some valves were not being
i tested as required by the ASME Section XI code. This change was based on ,
Section XI code guidance from the NRC which resulted in a different
understanding of testing requiremer.ts. Subsecuently the licelsee
performed a self-assessment of the program anc identified valves that
3
were not being adequately tested.
l The team reviewed the list of valves not presently in the Section XI
- test program and had further discussions with the licensee. The
- licensee initially stated that the valves that were not presently in the
'
Section XI program may or may not be testea pri,or to plant startup but
would be included in the next 10-year interval.. The team concluded if
the valves were required to be tested by the present code, then all of
! the vt.ives should be tested prior to plant startup and so informed the
! licensee. Completion of the Section XI valve testing is identified as .
'
. an inspection followup item (50 302/9714 03), Followup on Verification
' of ASME Section XI Valve Testing.
The team noted that many of the valves were stroked in accordance with
i
the Section XI program, but not in both directions. The following from
the licensee's self-assessment is a partial list of motor operated
valves not being fully tested. with noun name and added testing (Stroke
to open/ST0 and Stroke to close/STC):
i
j
_ _ . . _ . . . _ _ - _ . . . . _ _ _ _ _ _ _ _ _ _.
. .
21
VALVE TEST ADDED NOUN NAME
RCV-11 ST0 Pressurizer Relief Stop Valve
RCV-10 STC Power Operated Relief Valve
RCV 157 STC Hi Point Vent OTSG A
RCV 158 STC Hi Point Vent OTSG A
RCV-159 STC Hi Point Vent Pzr
RCV-160 STC Hi Point Vent Pzr
RCV-163 STC Hi Point Vent OTSG B
'RCV-164 STC Hi Point Vent OTSG B
EFV 11 ST0 EFP 2 Discharge to OTSG 3A
EFV-14 STO EFP 1 Discharge to OTSG 3A
EFV-32 ST0 EFP-2 Discharge to OTSG 3B
EFV-33 ST0 EFP-1 Discharge to OTSG 3B
EFV 55 ST0 EFW to 0TSG B
, . .
EFV 56 - ST0 EFW to.0TSG A +4- .
. -
- - EFW-57- - ST0- -
BSV 3 STC RB Spray Header Inlet
-
BSV 4 STC RB Spray Header Inlet Iso Valve
DHV 42 STC DHP-1A Suction from RB Sump
DHV 43 STC DHP-1B Suction from RB Sump
DHV-11 STC DHP-1A to MUP Suction
DHV-12 STC DHP 1B to MVP Suction
In addition to the motor operated valves listed above the licensee had
identified many containment isolation check valves that had not been
fully tested, other system check valves that had not been testeJ. relief
valves that had not been setpoint tested, and new valves installed under
modification packages that had not been tested.
During the inspection, ttie licensee stated that all of the identified
valves would be tested as necessary to meet the ASME Section XI
requirements.
The 1.eam also identified some -valves in.the MU&P system that were not
included in the licensee's ASME Section XI program, it appeared to the
team that these valves would need to be tested ,to meet the Section XI
testing req iirements. The following is a listing of the valves:
MUV-3 and MUV-9 These valves are not in'the licensee's Section
XI valve stroking program. They provide for HPI
train separation specifically detailed in the
licensee's high energy line break analysis.
MUV-53 arid MUV-257 These valves are not stroked quarterly or during
hot shutdown. They are stroked only during cold
shutdown. These valves provide minimum flow
protection for the HPI pumps.
=
_ _ _ _ , _ _ _ - - - - - - - - - - - - -
. .
22
MVV 53 and MUV 257 These valves are not stroked in the *0 pen"
direction. These valves provide minimum flow
protection for the HPI pumps and must be
reopened during various accident scenarios per
the E0Ps.
Based on this list the team noted that although the licensee's self+
assessment identified a number of valves that needed to be added to the
ASME Section XI program, it appeared that further review was necessary
1to ensure that every valve required to be tested would be included in
t ie Section XI program prior to plant startup.
The team also reviewed the surveillance data for valve stroking of
MUV-53 and MUV-257. The team noted that the stroke times for the two
valves were significantly different, MUV-53 being about 19 seconds and
. . . .cMUV-257,being about 33 seconds, Although the valves-were identical and
- - -
. the motor operators were the same, the gearing in theevalve. operators
was different, resulting in different times. A clear reason for the
differences could not be determined and the team noted that this
-
difference did not appear to affect the operability of either valve.
Further review in t!.is area determined that the surveillance procedure
maximum allowed stroke time appeared to be excessive in that it was 2
times the baseline stroke time for the valve. After further
discussions, the licensee provided documentation to show that the
maximum allowed stroke times were being revised to meet ASME Section XI
reouirements as documented in OMA-1988 Part 10, of the code. The team
noted that for MUV-257, which was slower due to different gearing, the
reduced maximum acceptable stroke time created a problem for the Section
XI acceptance criteria. The design maximum acceptable stroke time for
the valve was listed as 35 seconds. The historical test data and
baseline for this valve documented that by remote light indication, the
valve was stroking in approximately 33.1 seconds. Actual valve stroke,
as measured by MOVATS testing, documented that the valve was stroking in
about 34.5 seconds. This provided very little margin between actual
stroke ar.d an unacceptable condition. During further discussions with
the licensee. the licensee stated that this issue would be reviewed and
aapropriate actions would be taken to regain the margin necessary for
t1e Section XI program. The team noted that historical stoke time data
had not exceeded the design limit of 35 seconds.
'
c. Conclusions
An inspection followup item (IFI) was identified to ensure that all
required ASME Section XI valve testing will be completed as required.
A weatness was ident4fied for not identifying all valve testing as
needed to meet the ASME Section XI program.
A negative observation was identified for the marginal valve stroke
acceptance criteria for MVV-257.
__
'
'4
'
'
_ . . . . - _ .__m_____._ ___.._..____. ._
_ _____
. .
23
M2.5 Testina Of Coolina Fans AHF-15A/B
a. insoection Stone (61726 and 93801)
The team reviewed the testing of cooling fans AHF-15A/B.
b QM ervations and Findinas
~ '
The Decay Heat Closed Cycle Cooling System (DC) pump motor cooling fans
~AHF-15A/B receive a start signal during certain accidents such as the
design basis Loss of Coolant Accident. Because the DC pump motors were-
rated for continuous duty at ambient building temperatures up to 50
degrees C (122 degrees F) the fans were not normally required during
operation of the DC pump motors. Thus, the fans were only operated
during testing.
. . .. e < . . . . + 4.. .
.. . .
-
While res)onding to the team's question concerning operation and testing .
of the AHr.15A/B fans, the licensee determined that these fans were not
included in the vibration monitoring program. PC 97-7249 was issued to
-
address this issue. The licensee planned to include the AHF-15A/B fans
into the vibration monitoring program by adding them to procedure Al-
605A, " Condition Monitoring Program." The A fan was subsequently
operated and vibrations were determinea to be well within vendor
recommendations. The B fan was not available for testing at the time of
the inspection. The licensee planned to test the B fan when available.
Not including the AHF 15A/B fans in the vibration monitoring program was
considered a weakness.
c. Conclusions
A weakness was identified for not performing vibration monitoring of the
Decay Heat Closed Cycle Cooling System pump motor cooling fans.
M2.6 Testino of HP1 In.iection Valves
a. Insoection Scone
The team reviewed the electrical test program f,or the HPl Valves MUV-23,
24. 25. and 26 to verify that all control cir:uitry, interlocks,
'
contactors and power supplies were adequately tested in accordance with
the design.
b. Observations and Findinas
The team determined that the design and installation of the electrical
power supplies and controls for the HPI Valves MUV 23, 24, 25, and 26
was in accordance with the design and licensing basis described in the
FSAR: however the following deficiency was identified. FSAR Section
6.1.2.1.1. High Pressure injection (HPI) states in part. that "The four
HPI injection valves (MUV-23. 24. 25, and 26) may be supplied by either
of the two channels of_ the ES electrical buses through operation of
selector switches in the control room." The team found that the valves
.
. .- ______
. . .
. v
24
were designed and installed to be powered from either Es train A or ES
train B. The_ team also noted that HPl Valves MUV-23 and 24 were
normally supplied power by ES train A and Valves MUV-25 and 26 were
normally supplied power by ES train B with the alternate trains being
the backup.
The team requested information on how the valves were tested to verify
that they could be powered from both the normal and alternate power
supplies. In response to the team's request. the licensee performed a
review of their Surveillance Procedures (SP)-457 and SP-457A and found
that all contactors and associated control circuitry was not being
tested. The licensee stated that SP 457 and SP-457A performed stroke
time testing of the valves with the normal power supply but not the
alternate power supply. The team concluded that thi method .,f testing
did not verify that the valves can be powered from ti.a alternate power
. ... source.- The licensee agreed with the concern and documented the test
. - - . deficiency on ,PC 97-6960. The licensee-performed a^ broadness.retiew of
this issue and concluded that all other safety related' circuits that
utilize transfer switches were being properly tested. The licensee's
-
proposed corrective action was to revise SP 457 to include stroking HP1
Valves MUV-23, 24. 25. 26 using the normal and alternate power supplies.
The team noted that FSAR Section 6.1.3.1.1 "RCS Cold Leg Small Break
LOCA." Table 6-14. "ECCS Single Failure Analysis for RCS Cold leg Small
Break LOCA." and Table 6-19. "ECCS Single Failure Analysis for HPI
Injection Line Small Break LOCA." all described operator action during
a SBLOCA coincident with a LOOP and failure of one of the ES trains in
which the operator was required to swap the electrical power supply for
2 injection valves to the alternate energized source so that the HPl
valves can be opened to mitigate the event. The team concluded that
the failure to establish a test program and written procedures to verify
the HPI valves (MUV-23. 24, 25. 26) can be powered from the alternate
power supply was a violation of 10 CFR 50. Appendix B. Criterion XI.
Test Control, This item will be Nentified as a Violation (50 302/97-
14 04). Failure to Adequately Tr.st HPl Valves MUV-23. 24, 25. and 26
Power Selector Switches.
< c. Conclusions ,
A violation was identifie.1 for failure to adequately test HPl valves
MUV-23. 24, 25. and 26 power selector switches.
M2.7 Improper Calibration of Reactor Vessel Reduced Inventorv level
Jnstrumentation
a. Insoection Scooe (62707 and 93801)
The team conducted a review of completed calibration procedures for
instrumentation related to the decay heat removal and makeup and
purification systems. The team also reviewed completed calibration
procedures for instrumentation used to monitor plant conditions during
postulated accident conditions and subsequent operation of the Emergency
. _ --________ - _ _ _ _ _ _ _ _ _ _
. .
25
Core Cooling Systems (ECCS). The team conducted the review to determine
if the instrumentation was properly calibrated and calibrated at the
required intervals.
b. Observations and Findinas
The team reviewed the com)leted calibration procedures for various
instruments in tne decay leat removal system and the makeup and
purification system. The selected instruments included the borated
' water storage tank (BWST) level instruments. BWST temperature
instruments, makeu) tank (MUT) level instruments containment sump level
instruments, and t1e remote reactor vessel level instruments. In
general, the procedures were considered 19 be adequate to perform their
intended functions. S)ecific weaknesses are noted and are discussed in
the following paragrap is.
^ '
- -
Theteamnoted'thatthe'BWSTIandIMUTlevel-calibratioh$ceduresdid
not have procedural steps to direct the technician to verify that the
reference leg was properly filled or drained following calibration
-
activities. Refilling and draining the reference leg following
calibration activities was considered to be a skill of "le craft
evolution for these instruments. The team noted that the remote reactor
vessel level instrument calibration procedure provided detailed
instructions for backfilling the reference leg following calibration
activities. Ref1111ng or draining the reference legs would ensure that
the level instruments were operational prior to returning the instrument
to service. Having inconsistent procedural guidance for backfilling or
draining level instrument reference legs was considered to be a negative
observation.
The team reviewed the calibration of Reactor Vess,.1 Level Instruments
RC-201-LT and RC-202-LT. During the team's review of the completed
Remote Reactor Vessel Level Instrurnentaticn Calibration Procedure. SP-
195. it was noted that the procedure was inadequate in that it provided
inappropriate instructions. The team noted that following completion of
. the instrum " calibration and returning the instrument to service. SP-
195. Sectic . 4.7.1. required the technician to record the as-found level
in the clear tygon tubing (reactor vessel level indication / stand)ipe)
and to readjust the level transmitter to agree with the tygon tu)ing.
This resulted in the instrument being outside 1.ts calibration acceptance
criteria as documented in SP-195 in February 1996. The instrument was
miscalibrated by approximately nine inches.
Review of the SP-195 as-found data for the February 21. 1996,
calibration noted that RC-201-LT was out-of-calibration by approximately
0.89% from the desired output and that RC-202-LT was out-of-calibration
by approximately 4.1% from the desired output. The as found acceptance
criteria for RC-201-LT was +/- 0.36% from the desired output and the
acceptance criteria for RC-202-LT was +/- 1.3% frcm the desired output.
This indicated that due to previous miscalibration the instruments may
have been out of tolerance for the preceding calibration interval. On
February 25, 1996, the technicians miscalibrated RC-201-LT by
. .. .
. _ _ _ _ _
-_. __ ___ - _ -_
. .
26
a> proximately 1.4% and miscaliorated RC 202-LT by approximately 5.2%.
Tie as leftoutput
the desired accer'.nce criteria
(NOTE: The dif for bothininstruments
ferences values were duewas +/- 0.25% from
to the
instruments readirl different scales: RC-201 LT measures 128-176 feet
elevation and RC '.02-LT measures 128-138 feet elevation.)
The team noted that the reactor vessel level instruments were calibrated
on February 21. 1996. On Febru:.ry 2E. 1996. the instruments were
~
adjusted to read the reactor vessel level provided by the tygon tubing.
'The adjustments were approximately nine inches for both 1struments and
resulted in the both instruments being left outside the SP-195
calibration acceptance criteria. Procedurally requiring the technician
to make adjustments to the transmitter, thus miscalibrating the level ,
instruments, was considered to be an inadequate procedure and was
identified as a violation (50 302/9714 05). Failure to Provide Adequate
..
Procedure for Calibration of. Reactor Vessel Level Instrumentation for .
-
Reduced Inventory Operation. e ._ . .
'
After this issue was discussed with the licensee, the licensee initiated
-
PC 97-7243 which noted that. "After the calibration is complete. the
technician is instructed to cdjust the calibration of these instruments
to match the reading to the indicated level on the tygon tubing. This
adjustment takes the instrument out of calibration and is counter to the
intent of Generic Letter (GL) 88-17, which requires two independent
metheis of measuring level in the reactor vessel during lowered loop
operation."
In addition the team reviewed PC 97-6629 which was initiated on
September 24, 1997. The precursor card stated "SP-195 remote reactor
vessel level instrument calibration requires an as found calibration on
RC-201-LT and RC-202-LT. Following calibration I/C will adjust the zero
because the procedure requires the indications match :he sight glass
indication. Calibration is necessary, but finding the as-found data out 7
of tolerance and initiating precursor cards is wrong because we adjusted
it out with the zero adjust." In the Comments / Recommendation section of
the precursor card, the ins)ector noted the following. "Stop taking as
found data that will never 3e in tolerance" and " Procedure will need to
be changed and engineering must provide input.",
The team noted two significant problems with the above precursor card
statements. The first problem was that the licensee failed to identify
that the instruments may have been inoperable for an extended period
prior to the 1996 calibration. The team noted that the instruments were
found out of calibration on February 21. 1996, which may have been due
to readjusting the zero adjust during the previous calibration. The
second problem was that the licensee failed to identify that the SP-195
procedure was providing inappropriate guidance. The subsequent result
of this failure was that the recommendation section of the precursor
card recommended that the procedure be changed to stop taking as-found
data, which is used to monitor instrument drift problems.
_ _
,
.
. . ..
, ,
27
c. Conclusions
A negative observation was noted in that procedural guidance was
inconsistent in providing direction for backfilling or draining level
instrument reference legs.
A violation was identified for failure to provide an adequate procedure
for calibration of reactor vessel level instrumentation for reduced
inventory operation.
Weaknesses were noted for a )recursor card associated with SP-195 10
that it failed to identify tie inappropriate procedural guidance, failed i
to identify the inoperable condition of the reactor vessel level
instruments, and provided inappropriate recommendations to stop taking
as-found data.
-
.
n . .- . .
-
M3 Maintenance Procedures and Documentation - . .
M3.1 Technical Adecuacy of Maintenance Procedures
.
a. Insoection Scoce (93801)
The team reviewed a sample of maintenance work orders and supporting
documentation to assess the adequacy of work instructions and
documer.tation of work performed on the MU&P and DH systems. /pplicable
regulatory requirements included 10 CFR 50 Appendix B and the licensee's
Quality Assurance (0A) program.
b. Observations and Findinas
The overhaul of makeup pump (MVP) 1-A was documented on work order NUO
334472 dated May 15, 1996. The work order provided adequately detailed
instructinns for the work being aerformed. One exception noted by the
team was related to removal of t1e shrink-fit cou) ling hub from the
impeller shaft which required heating of the hub Jy a torch. A
arecaution stated a not-to exceed shaft temperature of 350 F during
leating but did not indicate how the temperature was to be monitored.
The craf t description of the work performed did not indicate how the
temperature was monitored to meet this precaution requirement. A review
of related maintenance training did not address.this action. The craft
personnel performing the overhaul stated that a temperature stick or
contact pyrometer would be used to monitor temperature. Tne licensee
initiated PC 97-7032 to address this item as a training deficiency.
Modification MAR 96-02-09-01 installed additional HPI flow indication
and was implemented by NUO 334292. dated April 3.1996. The work
instructions were adequately detailed for this complex maintenance
activity. Adecuate Ocality Control /0C) hold points were included to
verify indepencently critical procedure steps. Good configuration
control was maintained by an extensive alteration log which tracked the
determination and termination of instrument electrical leads. The work
performed was well-documented.
j
.. .
. . . .. . .
.
.. .
_
- - _ _ - _ _ _ _ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
,
. *
28
c. Conclusions
In general, procedures for complex mechanical maintenance activities for
the makeup and purification and decay heat removal systems provided
adequately detailed instructions. The procedures included appropriate
technical criteria. Quality Control (OC) hold points and OC involvement
were adequate. Documentation of completed work was good.
M3.2 Measurina and Test Eauinment (M&TE)
.
a. Insoection Scone (93801)
The team reviewed the licensee's use and documentation of M&TE during
maintenance on the MU&P and DH systems. Anplicable regulatory '
< .
requirements included 10 CFR 50 Appendix B and the licensee's Quality
, -. . Assurance.(OA) program. . -
% 7.: . .
-- . - .
-: m,_ .
b. Observations and Findinos
-
Use of M&TE was well documented in work packages. Initial conditions of
work procedures required verification that the M&TE was within its
calibration frequency. The licensee's program for control of portable
M&TE was documented in CP-146. "M&TE Calibration and Control." Revision
2. The M&TE assigned to the calibration laboratory was maintained in
accordance with this procedure and ensured that evaluations for previous
use of instrumentation found out-of-tolerance (00T) were completed in a
timely manner. However, the team identified that the program to control
the M&TE installed in the plant was deficient in that there was no-
process to accomplish previous use evaluations of 00T instruments. The
installed equipment included pressure gages and other 3rocess
instrumentation used in IST program testing. The cali) ration laboratory
was not responsible for the control of the installed M&TE.
In reviewing the calibration history of M&TE used in SP-340C "MUP 1-A,
MVP 1-B. and Valve Surveillance." Revision 14. the team noted that the
last calibration of the M&TE identified 00T conditions in several ranges
of the= instruments. The 00T instruments were returned to the specified
calibration range; however, there were no evalgations documented for the
impact on previous use of the instruments. The following instrument
calibrations were 00T: MU-22-P1 dated February. 15, 1996. MU-27-DPT
dated December 28. 1995, and MU-27-FI dated February 15, 1996. The team
identified this issue as a Violation (50 302/97 14 06). Failure to
Evaluate Out-of-Tolerance M&TE.
The licensee 1.iitiated PC 97-7046 on October 15, 1997, which identified
that there was no procedural requirement to notify the IST group when
gages used in IST were found 00T. This PC also identified the installed
gages used in IST surveillance. An extensi eness review was initiated '
by PC 97 7259 on October 23. 1997, and identified 19 examples of 00T
instruments used for IST which were not evaluated. The review included
an impact evaluation which concluded that the IST test results were not
adversely impacted.
1 _ _ _ _ _ _ _
.- -____ _ _ _ _ _ _ _ _ _ _ - _
..
_
.
.
. . .
.. .
. .
29
c. Conclusions
A violation was identified for failure to evaluate out of tolerance
M&TE.
The program for control of portable M&TE maintained by the calibration
laboratory was good.
M3.3 Procurement of Reolacement Parts and Ecuioment
a. Insoection St.ooe (93801)
The team reviewed a sample of procurement documentation referenced in
work order packages to assess the implementation of quality and
technical requirements for safety related equipment. These included
. .- procurement for valves MUV-23.-24.-25.-26. -541, and. DHV-21. . Applicable .
-
.
-regulatory requirements included 10 CFR-50 Appendix B and..the licensee's
Quality Assurance (QA) program.
-
b. Observations and Findinas
The following Purchase Orders (P0s) documented the quality and technical
requirements for valves installed in the MU&P and D4 systems:
. P0 F90223271 dated May 7, 1984 MUV-23.-24.-25,-26
. P0 PR3-1001 dated July 17. 1978 DHV-21 (original)
. PO E7726910 aated March 20. 1997 DHV-21 (replacement)
. P0 P423040 dated Dec. 16, 1980 MUV-541
The P0s included appropriate quality and technical requirements for
safety related equipment. Licensee audit documentation was available to
validate vendor Appendix B qualification. Receipt inspection
documentation verified the established receipt inspection criteria.
c. Conclusions ,
Procurement documentation for a sample of insta.lled MU&P and DH systems'
equipment demonstrated the implementation of appropriate technical and
quality requirements in the procurement process.
.. ___ __.
- - _ _ - - - _ - - - - - _ _ _ - - - _ - _ _ - . - - _
-,
e 5
30
M4 Maintenance Staff Knowledge and Performance
M4.1 Inadeouate Foreion Material Exclusion Control
a. Insoection Stone (62707 and 93801)
The team performed system walkdowns of the decay heat removal and makeup
and purification systems. The system walkdowns were performed in order
~
to evaluate overall system material condition and to identify any
tadverse conditions,
b. Observations and Findinas
During the walkdowns the team identified minor discrepancies, which were
turned over to the licensee for resolution. The material condition of
. ., -- -. the . systems and general condition of the auxiliary. building appeared to
- -
be acceptable. -The overall condition of the reactor building was
evaluated as poor. The team noted that in both buildings a significant
amount of maintenance and modification activities was still ongoing.
.
-While walking down sections of the decay heat removal system. located in
the vault area, the team noted that the "B" reactor building spray pum
had begn removed in order to perform maintenance on the pump impeller.p
The team noted that the disconnected piping and irstrumentation had been g
sealed per the licensee's foreign material exclusion program. The team 9
also noted that the motor had not been sealed following the maintenance
activities. The stator and field windings were clearly visible and,the
licensee had not established an exclusion area around the motor.
The team reviewed the Foreign Material Exclusion (FME) Control
procedure. CP-116A. Section 4.0 provided the instructions for
establishing an FME area. Se.; tion 4.1.1 directed the principle work
group supervisor to refer to Enclosure 1. FME Logic, as needed to
determine if an FME area was required. Enclosure 1 noted that if
tools / materials can fit through the opening, then establish an FME area
with controls as required per this procedure. Section 3.3.2 provided
guidance for installing temporary closures for FME areas.
The team noted that the "B" reactor building sp' ray pump motor was open
and FME controls were not in place. The licensee was notified of the
deficiency and promatly implemented the FME program. The licensee's
failure to follow t1e CP-116A procedural guidance for implementing the
FME program was identified as a violation (50 302/9714 07). Failure to
Follow Foreign Material Exclusion Procedure Requirements.
During the subsequent review of CP-116A. "FME Control." the team noted
that the procedure did not provide consistent guidance for implementing
the procedural requirements necessary for an effective FME program. For
example the principle work group supervisor was assigned the
responsibility of determining if FME controls were necessary, extent of
area, and detail of briefings with little guidance on how to perform the
responsibilities or the expectations for implementing the program. In
_ _ _ _ _ _ _ _ _ . l
_ _ _ - _ - - _ _ _ _ _ _ _
. *
31
addition, the team reviewed the licensee's self-assessment. CRSA 97-17,
dated September 10. 1997. The assessment noted that the FME procedure
was written in passive terms, did not directly address electrical and
I&C applications. and the procedure was filled with words that allows
implementation of FME to be optional . There was a lack of training by
personnel directly associated with the FME work processes and plant
implementation of FME was characterized as being inconsistent. Based on
the team observations and the licensee's self-assessment, the team
concluded that revisions to the FME implementing procedure were
necessary. -
c. Conclusions
A violation was identified for failure to follow foreign material
exclusion procedure requirements.
. . .
=- .
-
-
A-weakness was identified for inconsistent procedural.: guidance provided
by the foreign material exclusion program procedure CP-116A.
-
M7 Quality Assurance in Maintenance Activities
M7.1 Review of Open Items Trackina System in Maintenance - Maintenance
Backloa
a. Insoection Scooe (93801)
The team reviewed the maintenance backlog for the MU&P and DH systems to
assess the prioritization and scheduling of outstanding maintenance.
Applicable regulatory requirements included 10 CFR 50 Appendix B and the
licensee's Quality Assurance (QA) program.
b. Observations and Findinas
Outstanding maintenance for the systems was identified and arioritized
as a function of the System Readiness Review process. In t1e MU&P
system t Mre were 54 open maintenance work orders. 29 were designated as
restart issues and ap' proximately 20 of these remained open. In the DH
system there were six open work orders. four wqre designated as restart
issues and three of these remained open. A sponsor was assigned for
each restart item and the items were scheduled .for work.
c. Conclusions
The licensee adequately identified and prioritized the maintenance
backlog for the MU&P and DH systems as a function of the system
Readiness Review Process.
Team members assessed the licensee's performance relative to the
Maintenance processes in four of the five areas of continuing NRC
concern:
1) Management Oversight --- Adequate
_ - _-_
. .
32
2) Engineering Effectiveness --- Adequate
3) Knowledge of the Design Basis --- Adequate
4) Compliance with Regulations --- Adequate
5) Operator Pe-formance --- Not Evaluated
III. ENGINEERING j
El Conduct of Engineering
El .'1 Evaluation of Drawino Control Program
a. Insoection Scooe (93801)
The team reviewed the licensee's drawings in the control room and
control room work control center to verify that they were readily
. - m accessible. . legible, maint' . led in accordance .with the:-licensee.'s .
- - -
drawing control program, aw correctly reflected modifications being
installed during this outage.
-
b. Observations and Findinas
The team reviewed the following licensee procedures and discussed them
with licensee personnel:
. NEP-133. " Control and Approval of Drawings." Revision 8. dated
February 24. 1997
. NEP-212. " Processing of Modification Projecis by Nuclear
Projects." Revision 19. dated September S. 1997
. NEP-271. "As-Building of Modification Approval Records. Commercial
Grade Work Requests, and PEERES." Revision 13. dated March 31,
1997
. DC/RM 310. " Nuclear Information Resources Department Control of
Prints and Aperture Cards." Revision 18. dated May 30. 1997
Also, the team reviewed the status of modificat; ions being installed this
year and then reviewed control room and control room work control center
copies of drawings as listed in Appendix A. .
During the review. three discrepancies were noted. Drawing Index B-208-
026 had not been updated to include the new electrical diagram for motor
operated valve EFV-12 (MAR 96-10-10-03). Revision of this drawing index
was not included in the modification package, but the modification was
still open, and a final licensee review of the modification package
might have caught the error. The licensee wrote a Precursor Card on
this discrepancy. Drawing FD-302-082. Sheet 1 of 3. had a temporary
Fast Turnaround Drawing stapled to it, showing the new Emergency
Feedwater (EFW) cavitating venturis (MAR 96-10-02-01). However. Drawing
FD-302-082 had been permanently revised to include the EFW cavitating
venturis, and the temporary Fast Turnaround Drawing should have been
.
. .
_ _ ____________
. . . . . . .
. 6
33
removed. The licensee wrote a Precursor Card on this discrepancy.
Also, the licensee's computerized configuration management information
system (CMIS) drawing index had not been updated to reflect one drawing
revision. The licensee found that this discrepancy had previously been
identified on a Precursor Card.
Overall, the team found that the control room and control room work
control center drawings were readily accessible and legible. The
drawings generally were maintained in accordance with the licensee's
' drawing control program and the one-line drawings correctly reflected
modifications being installed during this outage. Most of the drawings
were produced by computer and consequently were very clear and legible.
c. Conclusions
.. The team concluded that the. licensee's drawing control: program.-for .
- -
- control room critical drawings, was adequate. -:n
'
El.2 Desion Review of Thermal Exoansion Chambers (MAR 96-10-04-01)
.
a. Insoection Scoce (93801)
The team reviewed the installed thermal expansion chambers modification,
the related modification package 10 CFR 50.59 safety evaluation, and
NRC regulations and guidance.
b. Observations and Findinas
During a walkdown of the makeup and purification system, the team
identified a concern with the thermal expansion chambers installed this
year by the licensee in response to Generic Letter 96-06. The licensee
had installed 12 thermal ex)ansion chambers outside the reactor
building, in the auxiliary Juilding. The purpose of this modification
(MAR 96-10-04-01) was to protect the piping between closed inboard and
outboard reactor building isolation valves from potential over-
pressurization due to thermal ex)ansion of fluid. Each thermal
expansion chamber was connected )y 3/8 inch tubing to a section of
piping between an outboard reactor building isqlation valve and the
reactor building. The team was concerned about the exposure of the
thermal expansion chambers and 3/8 inch tubing .to accidental damage and
the fact that the installations in effect bypassed one of the two
reactor building isolation valves.
The thermal expansion chamber of most concern to the team was connected
to the letdown line. It was the only thermal expansion chamber that
would be continuously exposed to reactor coolant system (RCS) pressure
during normal plant operation. The letdown line thermal expansion
chamber was mounted on the floor of the makeup valve alley in the
auxiliary building. It was connected to the letdown line by about 15
feet of 3/8 inch stainless steel tubing. The tubing was exposed to
- - - - - -
- _ - _ _ _ _ _ _ _ _ _ _
. 6
34
being accidentally stepped on or hit and consequently ruptured. Also,
there were no isolation valves between the thermal expension chamber and
the letdown line.
The team noted that the letdown line thermal expansion chamber
installation did not conform to current NRC guidance. 10 CFR 50.
Appendix A. Criterion 55. Reactor Coolant Pressure Boundary Penetrating
Containment, requires that each line that is part of the reactor coolant
pressure boundary have one automatic or locked closed isolation valve
inside containment and another one outside :ontainment. Further, the
isolation valve outside containment must be located as close to
containment as practical. In addition, other appropriate measures must
be taken to minimize the probability or consequences of an accidental
rupture of these lines or lines connected to them. The letdown line
thermal expansion chamber had no isolation valve outside the reactor
. . building, was not located as close to the reactor building as practical.
- -
and its approximate 15-feet of 3/8 inch tubing was not protected from
accidental rupture. However, the licensee stated that 10 CFR 50.
Appendix A did not apply to Crystal River since its construction permit
-
was issued prior to May 21, 1971. The licensee stated that this
inapplicability of Appendix A was described in NRC position paper SECY-
92-223. " Resolution of Deviations Identified During the Systematic
Evaluation Program." dated September 2. 1992.
Similarly, the letdown line thermal expansion chamber installation did
not conform to NRC guidance in Regulatory Guide 1.141 " Containment
Isolation Provisions for Fluid Systems " or related ANSI N271-1976.
" Containment Isolation Provisions for Fluid Systems." The installation
also did not conform to the apparent intent of NRC guidance in
Regulatory Guide 1.11. " Instrument Lines Penetrating Primary Reactor
Containment." The licensee had not committed to these Regulatory Guides
or industry standards.
The licensee's position with respect to 10 CFR 50.59 was that the
thermal ex)ansion chamber modification was in compliance, because a
break in t1e 3/8 inch letdown line thermal ex)ansion chamber tubing
would not be considered an accident. Such a 3reak would result in RCS
leakage that would be less than the normal makeup capacity. Therefore,
such leakage would not be considered a loss of coolant accident, and
operators would not enter emergency operating procedures. The licensee
stated that potential accidents analyzed in the Final Safety Analysis
Report (FSt.R). such as a letdown line rupture outside the reactor
building. considered only reactor coolant leaks that would exceed the
normal makeup capacity. The team noted that the FSAR Chapter 14
analysis considered a rupture of the letdown line that was downstream of
the two reactor building isolation valves and therefore readily
isolable. The FSAR analysis did not consider a rupture in tae short
section of the letdown line between the reactor building and the
outboard reactor building isolation valve as a credible event.
The team explored whether the potential consequences of a break in the
3/8 inch letdown line thermal expansion chamber tubing might exceed
_ _ _ - _ _ _
__ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
. 4
35
those of the FSAR Chapter 14 letdown line rupture outside the reactor
building. The team noted that the licensee's ability to isolate a leak
quickly in the 3/8 inch tubing would be limited. Installed valves
between the reactor coolant system and the thermal expansion chamber by
the end of this outage will include:
. an isolation valve at the inlet to each of the three letdown
coolers (these motorized valve operators are located inside the
reactor building, non-safety related, and powered from non-safety
power)
e an isolation valve at the outlet from each of the three letdown
coolers (one with a manual valve operator and two with motorized
valve operators located inside the reactor building, safety-
related. and powered from the A train ES bus) _
I - .
aninboardletdownfinecontainmentisolationM[veb(witha
motorized valve operator located inside the reactor building,
safety-related, and powered from the A train ES bus)
.
Thus a rupture of the letdown line thermal expansion chamber tubing.
coincident with a loss of offsite power and a failure of the A train
EDG, would result in a reactor coolant system leak that would bypass the
reactor building and would be unisolable from outside the reactor
building. The leak rate would be about 75 gpm at a tem 3erature of about
100 degrees F. which would be well within the normal maceup capacity of
about 117 gpm. The loss of offsite power would result in a reactor trip
and operator entry into the emergency operating procedures (EOPs) in
addition to being in the abnormal procedure for RCS leak. The team
reviewed the procedures that the operators would be using and concluded
that cooling water to the letdown coolers would be temporarily lost with
the loss of offsite power, but then would be restored when the B train
EDG and engineered safeguards (ES) equipment automatically started. The
licensee estimated that, with the letdown coolers in operation. it would
take about three hours to release the same amount of RCS water into the
auxiliary building (and have the same offsite dose consecuences) as in
the FSAR letdown line rupture analysis. The licensee jucged that it
would take less than three hours for the Techni, cal Support Center (TSC)
to be manned and operators sent into the reactor building to isolate the
leak manually. The team judged that isolation .of the leak within three
hours was reasonable, even if operator entry into the reactor building
was complicated by the presence of airborne radioactivity in the
auxiliary building. The team concluded that the consequences of a break
in the 3/8 inch tubing for the letdown line thermal expansion chamber,
coincident with a loss of offsite power and = failure of the A EDG.
would probably not exceed the consequences 01 the letdown line rupture
analyzed in the FSAR.
The licensee's applicable design criteria were described in the FSAR.
They included FSAR Section 1.4.51. Criterion 51 - Reactor Coolant
Pressure Boundary Outside Containment: Section 1.4.53. Criterion 54 -
Containment Isolation Valves; and Section 5.3.2. System Design (for
_ _ _ _ _ - _ _
_ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ._-_
.
.
. 6
36
fluid penetrations that require isolation after an accident). Section
1.4.51 defined reactor coolant pressure boundary as those piping systems
or components which contain reactor coolant at high pressure and
temperature. It further stated that. Other than the sample lines, all
piping and components that may contain reactor coolant outside the
reactor building are at low temperatures. Thus any leakage would be
collected by the Waste Disposal System and there would be no significant
environmental dose. Section 1.4.53 stated that leakage through all
fluid penetrations not serving accident consequence limiting systems is
~ minimized by a double barrier so that no single credible failure or
malfunction of an active component can result in loss of isolation or
intolerable leakage. It further stated that the detailed implementation
is described in Section 5.3.2. Section 5.3.2 (and referenced Table 5-4)
described the letdown line reactor building penetration as a Type I
penetration, for which each line connecting directly to the RCS has two
.. _ reactor-building.. isolation valves. . One valve is external.and the other
- is internal to the reactor building. The licensee stated .that they plan -
to change the FSAR description of the letdown line reactor building
penetration to Type I/IV. For a Type IV penetration, lines that
-
penetrate the reactor building and are connected to either the building
atmosphere or the RCS have a blind flange or a normally locked-closed
valve
The licensee stated that the letdown line thermal expansion chamber
installation met the FSAR design criteria. A break in the 3/8 inch
tubing would not result in intolerable leakage, and the installed
isolation barriers met the detailed criteria of Section 5.3.2. The
licensee stated that the letdown line thermal expansion chamber met the
Type IV penetration design because it was the same as a blind flange at
the end of the 3/8 inch tubing.
The team determined that further NRC review of this issue was warranted
to evaluate if the licensee's interpretations of the licensing basis of
the plant were correct, and if the licensee's installation of the
letdown line thermal expansion chamber was acceptable.
c. Conclusions
An unresolved item was identified (50 302/97-14'-08). NRC Evaluation of
Acceptability of Thermal Expansion Chambers for. Containment Penetration
Line Modifications for GL 96-06.
E1.3 Cross-Connected HPI Discharae Head.at
a. Insoection Scoce (93801)
The team conducted a review of the operation. testing and design of the
high pressure injection system. The review was specifically focused on
the HPI system pump discharge header and associated valves.
l
l
- _ _ _ - _ _ _ __ __ _ _ _ _
_,
. 6
37
b. Observations and Findings
The team noted that the licensee operated the HPI system with the
discharge header of the high head safety injection pumps cross-
connected. This mode of operation did not provide for train separation
between the "A" and ~B" trains of high head safety injection, without
operator action. However, this mode of operation )rovided for adequate
flow for high head safety injection coincident wit 1 a piping failure and
was approved by the NRC in 1978 per Technical Specification Amendment
16. Based on NRC "Open Item" (50-302/79-30-06), the licensee installed
motor operators on MUV-3 and MUV-9. HPI discharge header cross-connect
isolation valves, to " enable remote isolation." This open item was
closed in NRC Inspection Report 50-302/81-19. In 1982, it appeared that
the licensee removed sower from MUV-3 and MUV-9 in order to meet the
10 CFR 50 Appendix R rire Study requirements and documented that plant
. change in a letter to the NRC. The letter to.the NRC (#3F-1082-32. File
- -
3-F-2) was dated October 29, 1982. :_. _
Based on documents provided to the team related to "HPI Common Discharge
-
Line Licensing Basis." the team noted that the licensee's High Energy
Line Break Analysis (3F0589-20 as approved by the NRC under a document
numbered 3N0689-02), stated the following. "The three. 100% capacity
MUP's discharge to a common header. allowing any single pump to supply
multiple injection lines. This common discharge header contains both
manual and remotely operated valves which can isolate any disabled
section, ensuring three of five potential flow paths are available to
supply the RCS with borated water." The analysis also stated that
"There are five potential flow paths for borated water into the RCS.
four high pressure injection lines and one reactor coolant pump (RCP)
seal injection line. Each of these five lines is independent and can be
placed in service or isolated from the control room.~
Additional review of Florida Power Company (FPC) Submittal (#3F-1082-32)
noted that ' Spurious operation of MUV-3 and MUV-67 will not affect
shutdown o]eration unless MUP-1B is being used in place of MUP-1C.
Whenever t1is particular pump alignment is used. MUV-3 and 62 will be
locked open at the motor control center (MCC) to preclude any
detrimental effects. Likewise, s]urious operat; ion of MUV-69 will not
affect shutdown operation unless 4UP-1B is being used in place of MUP-
1A. Whenever this particular pump alignment is.used. MUV-69 will be
locked open to preclude any detrimental effects. HUV-9 will be locked
open at the MCC and will remain open throughout plant shutdown
operation." Based on the wording in the licensee's submittal, the team
concluded that the intent of the submittal was that the valves would
only be deenergized during shutdown operation dependent on system
alignment which was in conflict with deenergizing both valves during
plant operation.
The team noted that with power removed from the motor operators, the
control room operators would not have the capability to operate remotely
the common discharge header cross-connect valves to isolate any disabled
section of piping. This appeared to be in conflict with the High Energy
,
_ _ _ _ _ _ _
_ _ _ _ - - _ - _ _ _ _ _ _ _ _ _ _ _ - _ _
. 6
38
Line Break Analysis, the 10 CFR 50 Appendix R submittal and with the
intent of TS Amendment 16. It appeared that the plant had not been
operated as originally designed after the HPI discharge header cross-
connect valves were deenergized. The alignment did not provide for
train separation of the High Head Safety injection System or the ability
for the control room operators to remotely operate the valves. This
issue was identified as an Unresolved Item (50 302/9714 09). NRC
Evaluation of Acce tability of Makeup System Trains Crosstied Without
Ability to Remotel Isolate Trains.
In addition, the team noted that the two HPI system discharge motor
operated cross-connect valves. MUV-3 and MUV-9. were not included in the
ASME Section XI valve testing program. Based on the apparent need to
have the capability to be remotely operated from the control room to
meet the High Energy Line Break Analysis, it appeared to the team that
these valves should have been included in the ASME .Section XI . valve _
-
stroke testing program. (This issue was also noted in.Section.M2.4 of
this report).
-
c. Conclusions
An unresolved item was identified for NRC evaluation of the
acceptability of the makeup system trains crosstied without the ability
to remotely isolate the trains.
El.4 Mechanical Desian Reviews
a. Insoection Scope (93801)
Team members reviewed selected calculations and modifications associated
with mechanical design of components for the makeup and purification and
decay heat removal systems.
b. Observations and Findinos
1) Calculations
Calculations were reviewed in several related areas. The licensee noted
that the original piping and support calculatio'ns for the large bore,
safety related piping had not been located. Specific problems that were
identified included: weld attachments (missing welds), temperature cut-
off/ lack of thermal analysis. anchor design uncinched U-bolts acting as
two-way restraints. missing support calculations. hard copies of pipe
stress calculations. consistency between design packages, and drawings
matching the as-built configuration.
During the current outage. the licensee had started to reconstruct
piping and support design calculations by reanalyzing all piping
" touched" during the outage. For example, the letdown lines were
modified by installation of inside reactor building isolation valves.
The stress analysis for the letdown lines was performed to demonstrate
compliance with the design basis code (ANSI B31.1. 1967). However, the
. _ _ _ _ _ _ _ _ _ _
. - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. t
39
team noted that in the absence of previous design calculations it was
not possible to assess loss of margin due to the piping modifications
An Inspeccion Followup Item was identified (50 302/971410). NRC
Followup that Licensee Approach for Resolution of Deficiency Associated
with Lack of Documentation for Original Piping and/or Support
Calculations is Acceptable.
Review of precursor card PC 97-3306 disclosed that the calculation for
the makeup tank vapor pressure during tank drain down was in error. The
corrective action determined via the PC process had not been carried
out. The licarisee wr ote precursor card. PC 97-7252. to correct the
problem and close the original precursor caro. The calculation would be
voided per Procedure NEP-213 put in place October 15. 1997.
The calculation verification (quality assurance) program was reviewed
,
and.found to be consistent with the. normal industry.pract-ices. .
-
Procedures NEP-135, 213. and 261 were reviewed and found to be
acceptable. The team noted a positive observation in that all software
was subjected to annual reverification in addition to reverification
-
following modification.
A copy of the package to be submitted in response to Generic Letter 97-
04 was provided to the team. The generic letter requested evaluation to
ensure adequate net positive spction head (NPSH) will exist to support
operation of two low pressure injection pumps, building spray pumps, and
one high pressure injection pump when the reactor building is in a
flooded condition. The package was considered to be a thorough
evaluation of the NPSH requirements for the low pressure injection,
building spray, and high pressure injection pumps.
2) Computer Codes
The team noted during the inspection that the submitted technical
specification change request number 210 was confusing in that it
referred to small break LOCA analyses performed with the RELAP5 computer
code. The analysis code of record for the Crystal River Unit 3 facility
was the CRAFT 2 code. The team pointed out that changing the code of
record required the review and approval of the SRC under the conditions
of 10 CFR 50.46. The licensee provided access to analysts from the
vendor. Framatome Technologies Incorporated, who clarlfied the use of
the computer codes. In this instance RELAP5 was used for engineering
scoping calculations and not for licensing basis calculations. The team
agreed that this is a valid use that did not require NRC review and
approval.
3) FSAR Revision
The team noted that the licensee was reviewing the Crystal River Final
Safety Analysis Report and had identified information which was out of
date and erroneous. The licensee had precursor cards prepared to
correct the sections and will submit revised content with FSAR Revision
24.
.
.
_ _ _ _ _ _ _ _
1
. 4
40
The team noted that sensitivity analyses nre being conducted to verify
that the identified limiting SBLOCA cases had not been adversely
impacted by additional single failures. HPI isolation criteria, or
uncertainties in flows. The licensee stated that prior to restart the
SBLOCA documentation would be reissued to reconcile any calculational
differences between the 1996 documented SBLOCA cases and those based on
the as-measured HPI pump characteristics. The licensee stated that the
limiting case SBLOCA peak cladding temperature (1859 F) had not
-
changed. The main requirement identified by the analyses was that full-
' flow from at least one HPI pump must inject adequate ECCS water into the
RCS through all four cold leg nozzles within 10 minutes following
engineered safety features (ESF) actuation on low RCS pressure or loss
of adequate subcoooling margin.
4) Makeuo Pumo 1A Test
, . - --
.. .. 4. ~ . . .
- -- -
The-team reviewed the results of Makeup Pump 1A tests.:run.bnder the test
procedure PT-444. Acceptance criteria stipulated in the procedure were
not met. However, the licensee stated the pump met the licensing basis
-
calculations since the test acceptance criteria had additional margin.
The licensee had scheduled a reperformance of the test in Mode 3 during
restart. The new test will have acceptance criteria based on pump
requirements derived from the licensing basis analyses.
5) Valve Hardware Items
The air operated valve MUV-64, in the Makeup Tank to Makeup Pump inlet
header was modified in the past to remove the air operator and replace
it with a manual hand wheel. At that time position indication was
removed. Position indication has been restored in the control room by '
providing full open/ closed indication taken from the Limitorque
switches. The team considered this modification as positive in
providing operator control panel indication.
c. Conclusions
Licensee performance in the mechanical engineering aspects of the makeup
and purification and decay heat removal systems, was judged by the team
to be acceptable.
'
E1.5 Electrical Desian Reviews
a. Insoection Scooe (93801)
Team nembers reviewed selected calcuY. ions and modifications associated
with electrical design of components 1or the makeup and purification and
decay heat removal systems.
b. Observations and Findinos
The team found that in general electrical calculations had not been
updated since 1992. Specifically, the team found that several overload
1
_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ - _ - _ _ _ _ _ _ _
. s
41
relay and pn Rive relay setting calculations had not been revised to
incorporate ( s resulting from modifications. For example, the team
found that Cai t. ion E-90-0033. " Overload Protection Calculations For
MCC ES 3AB." Re sion 9. recommended that the N23 overload relay thermal
element for Valve MUV-18 be changed to N18. A plant modification was
approved (MAR 91-02-02-01) to replace the N23 element with a N18.
Later, another calculation. E-92-0036. Revisi'n 0, determined that the
element could cause a nuisance trip during low bus voltage conditions
and should be changed to a N19 element instead of the N18. Field Change
Notice #3 revised the MAR 91-02-02-01 to require that the existing N23
overload heater element be re) laced with a N19 element instead of the
previously identified N18. T1e field change notice (FCN) was
implemented and the electrical one line drawing EC-206-058. Revision 18.
was updated to show that a N19 heater element had been installed for
MUV-18. The team found that the selected overload heater element was
. . . acceptable. However the licensee failed to update calculation E-90- _
- -
0033. Revision 9. to show that the overload heater element 1had been
changed from N18 to N19. This example was typical of other overload
calculations that had not been updated.
.
The team found that the problem with electrical calculations not being
-
updated had been areviously identified as a restart concern and was
being tracked as Restart Issue OP-6. In addition. the team noted that
~
NRC had issued tscalated Enforcement Action EA 96-365 et al Violation B
(02013). (previously EEI 96-12-04) for use of unverified electrical
calculations to support modifications. The team found that the
corrective actions for OP-6 addressed part of Violation B of EA 96-365.
The Violation was still open, pending completion of the licensee's
Electrical Calculation Extent of Condition Assessment Program and ~
implementation of other corrective actions. The licensee provided the
team an overview of the calculation program and the team concluded that
if the 3rogram was implemented as discussed, all calculation impacts
should 3e identified.
During the review of overload relay calculations, the team identified
two examples where drawings were in error and had not been corrected by
the licensee. The team noted that electrical one line drawings EC-206-
058. Revision 18. and EC-206-075. Revision 19. , incorrectly identified
the motor full load ampere (FLA) ratings for MOVs DHV-41 and MUV-58.
respectively. Design Drawing EC-206-058 for DHV-41 indicated the motor
had a FLA rating of 2.6 amperes when the actual rating was 2.8. Design
drawing EC-206-075 for MUV-58 indicated the motor had a FLA rating of
3.0 amperes when the actual motor rating was 2.3. The licensee
documented these problems on Precursor Cards #97-7115 and 97-7134 for
tracking and corrective action. The team reviewed preliminary copies of
Revision 3 to Calculations E-91-0026 and E-91-0027 (Emergency Diesel
Generator "A" and "B" Loading Evaluations) and found that the design
engineers were or had been aware of the discrepancies on the subject
drawings but had not initiated a Precursor and/or Drawing Change Notice
to have the drawing deficiencies corrected. The team concluded that the
licensee's failure to identify promptly and correct the deficiencies on
drawings EC-206-058. Revision 18. and EC-206-075. Revision 19, was a
_ _ _ _ _ _ _ _ _ _ _
o >
42
violation of 10 CFR 50. Appendix B. Criterion XVI. Corrective Action.
This item is identified as an additional example of Violation (50-
302/97 14 02). Failure to Assure that Conditions Adverse to Quality Are
Promptly Identified and Corrected.
The team performed a walkdown of the overload relays and heater elements
for HPI Valves MUV-23 and MUV-24 and found that the overload relays were
installed for manual reset instead of automatic as stated in the FSAR.
' '
The team noted that~FSAR Section 6.1.2.4 (at Page 6-11) stated that
~ motor operators for ECCS valves would have motor overload 3rotection
with automatic reset. A Precursor Card was initiated by tie licensee to
document the problem and to implement corrective action. The team
concluded that the licensee's failure to ensure that the overload relays
were installed in the automatic reset position as stated in the FSAR was
a violation of 10 CFR 50. Appendix B. Criteria III. Design Control.
.. .-
This : item is identi.fied as a Violation (50 302/9714-11)r.0verload _
- -
Relays Not Installed as Automatic Reset as Stated in FSAR.:. -
c. Conclusions
.
Licensee performance in the electrical engineering aspects of the makeup
and purification and decay heat removal systems was judged by the team
to be acce) table. However, the adequacy of electrical calculations
could not De judged at this time because corrective actions have not
been completed to update the calculations. This was identified by the
licensee as a restart issue and will be inspected by NRC as part of the
closecut of Violation B to Escalated Enforcement Action EA 96-365.
A violation was identified for failure to assure that conditions adverse
to quality are promptly identified and corrected.
A violation was identified for overload relays not installed as
automatic reset as stated in the FSAR.
E1.6 Instrumentation and Control Desian Reviews
a. Insoection Scooe (93801)
Team members reviewed selected calculations and modification approval
record (MAR) packages associated with instrumentation and control design
of components for the Makeup and Purification System and the Decay Heat
Removal System. These packages were reviewed to: (1) determine the
adequacy of the safety evaluation screening and the 10 CFR 50.59 safety
evaluations. some of which included the introduction of digital
equipment: (2) verify that the modifications were reviewed and approved
in accordance with the Improved Technical Specifications (ITS) and
applicable administrative controls: (3) verify that the modifications
were being instelled as required by the licensee's procedures and had
proper sign-offs: (4) verify that the FSAR. Enhanced Design Bcsis
Document (EDBD). drawings, and applicable procedures were being updated.
, and (5) verify that post-modification testing requirements were
adequately specified. Team members conducted field walkdown inspections
- _____ __-
_ - . - - - - - - - - _ _ . - - _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
q b
,
43
to examine selected portions of the Makeup and Purification System and
the Decay Heat Removal System. Team members also reviewed Precursor
Cards ">C) associated with these systems.
b. Obser;,tions and Findinas
The MAR packages reviewed each had the engineering design portions
completed. None of the MAR packages reviewed were fully completed and
closed out. The following MARS were inspected:
. MAR 97-06-21-01. Reolacement of DH-38-dPT & DH-38-F11
The purpose of this modification was to improve the accuracy and
readability of the Low Pressure Injection (LPI) Crossover Flow
indication in the Decay Heat (DH) Removal System by upgrading the
flow loop instrumentation. . The upgrade was required for the . -
--
- -
implementation of recent-changes in the post-LOCA response
strategies that use Hot leg injection as a means to prevent post-
.
- MAR 95-09-04-01. BWST Narrow Range level
This modification added instrumentation to provide the operators
with more accurate indication of the level in the Borated Water
Storage Tank (BWST) in the top four feet of the tank. The BWST
level indicators that were in use before this modification were
not changed and continued to provide BWST level indication over
the entire range of tank contents, as required by Regulatory Guide
1.97. The instrument loop errors associated with the earlier
level indicators were so large they created a burden upon the
operators when maintaining the BWST level within the limits
required by the Technical Specification. The added narrow-range
instrumentation provided the operators with BWST level information
for the u)per four feet of the tank that had much less instrument
error. T11s reduced the burden upon the operators.
The team found the MAR packages to be complete. Team members identified
no discrepancies between the MAR packages and t
Team members found the 10 CFR 50.59 safety eval,he
uations FSAR.
to be EDBD. or ITS.
thorough
and technically adequate. Team members found no discrepancies between
the implementation of digital instrumentation introduced under the MARS
and the guidance of EPRI Report TR-102348 as clarified by Generic Letter
95'-02.
c. Conclusions
Licensee performance in the instrumentation and control engineering
aspects of the makeup and ]urification and decay heat removal systems
was judged by the team to 3e adequate. The MAR packages reviewed were
technically adequate and were being implemented in accordance with the
_ _ _ _ _ _ _ _ _ _
, .
44
licensee's requirements and NRC regulations. The licensee's, procedures
provided adequate controls for implementation of the licensee's design
control process.
E2 Engineering Support of Facilities and Equipment
E2.1 Indeoendent Reactor Vessel Level Instruments per Generic Letter (GL) 88-
ll
~
a'. 'Insoection Scooe (93801)
The team reviewed the design and calibration of the reactor vessel level
instruments used during reduced inventory operations. The primary focus
of the inspection activity was on the calibration of the instruments as
documented in Section M2.7 of this report. This section of the report
. . focussed on the licensee commitments related to GL 88317,and the. actual ..
-
design of the level transmitters. .
e m, _ . .
b. Observations and Findinos
.
The team reviewed the design of the reduced inventory reactor vessel
level instruments and noted that'the instruments were not independent.
The team noted that the instruments used the same reference leg and
condensing pot and also used the same sensing line. The instruments
were noted to be electrically independent.
lant and procedure changes and
GL 88-17 recommended
specifically, recommendationvarious
( p#4). " Provide at least two independent,
continuous RCS water level indication whenever the RCS is in a reduce
inventory condition." In response to GL 88-17. letter dated January 4
1989. the licensee stated "FPC will complete a modification to provide a
single channel RCS water level instrumentation with indication in the
control room in the range needed to monitor RCS water level in Refuel 7
'
beginning in the fall of 1989...FPC will evaluate the need for and best
means to achieve an additional channel of RCS level instrumentation.
Installation will be completed by Refuel 8 presently scheduled for the
fall of 1991."
The NRC responded to the FPC submittal in a let'ter dated July 7. 1989,
in which the NRC stated "You have not stated what type the level
measurement systems are. or if they will have alarms. If they will not
have alarms the indications will need to be periodically checked and
recorded by operators. You also indicate that only one method of level
measurement is currently available. This is acceptable in the short
term: however. for longer term. at least two independent level
indications must be provided in the control room."
In a letter dated May 18. 1990. the NRC informed FPC that further review
of GL 88-17 would be completed under Temporary Instruction (TI)
2515/103. The letter also stated "You are requested to inform the NRC
in writing when the action has actually been implemented and the
modifications are determined to be operational." In a letter dated
. .
45
June 29. 1990. FPC informed the NRC that all actions for GL 88-17 had
been completed ahead of the original estimate. 'All actions identified
in our response with a completion date at the end of Refuel 7 and Refuel
8 have been completed in Refuel 7."
NRC inspection report (IR) 50-302/91-04, stated that 'It was noted by
>
the ins)ector, that the two installed remote reactor level instruments.
RC-201 _T and RC-202-LT, have common reference lines and sensing
~
lines.... It does not appear that the licensee is maeting the intent of
'GL 88-17 in having two independent level channels."
During the inspection the licensee indicated that no further responses
to GL 88-17 were submitted to the NRC and the concern with the lack of
independence due to common reference and sensing lines had not been
addressed. Based on IR 91-04 engineering initiated REA 92-0601, on
. .
.. May.22. -1992. "to request an additional RCS level transmitter and .
- -
instrument string that-used different taps than RC-201-LT and RC-202-
LT." The documented response to the REA was "Use as is'."
-
The team continued to discuss this issue with the licensee. The team
was concerned with the present design because the two reduced inventory
instruments and the standpipe measurements all used the same taps. In
addition, the licensee was adjusting the level instruments to read the
same as the standpi3e and this process could lead to errors on all of
the indications. T1e licensee stated that no other taps existed to
provide the independence requested by GL 88-17 and noted that this had
also been the case when the reactor vessel level instruments, required
by NUREG 0737, were installed. The team noted that reactor vessel level
transmitters RC-164-A and RC-164-B were connected to common reference
and sensing lines.
The team noted that there were three independent sensing lines with
independent condensing pots and three independent sensing taps. These
were used to measure reactor vessel level with RC-201-LT. RC-202-LT. RC-
163-A RC-163 B. RC-164-A RC-164-B and the two standpiac levels. It
appeared to the team that train independence for both t1e reduced
inventory and accident reactor vessel level instruments could be
obtained without major modifications to the RCS,. Pending further
review, the lack of train independence of the reduced inventory reactor
vessel level instrumentation is being identified as an Unresolved Item
(50 302/97-14 12) NRC-Review of Licensee Response to GL 88-17 Associated
With-Reduced Inventory Operation.
On October 6. 1997, the licensee completed the reportability evaluation
for PC 97-6637 to address concerns with implementation of
recommendations from GL 88-17. The PC documented that it was "a
condition that is outside of the Licensing Basis, rather than a Design
Basis concern. This is not reportable under 10 CFR 50.73." Based on PC
97-6637 it a)peared to the team that the licensee had recently
resurfaced tie issue; however. final resolution was still pending at the '
close of the insoection.
_ __ _ ______________ __n
. .
46
c. Conclusions
An unresolved item was identified for NRC review of the licensee
response to GL 88-17 associated with reduced inventory operation.
E2.2 ASME Section XI Pumo Testina
a. Insoection Scooe (93801)
~ ~
"The team reviewed the program for pump testing related to the decay heat
removal and the makeup and purification systems.
b. Observations and Findinas
<
The team reviewed the
.. .. . .and.the-makeup pumps. .Thepump
review.testing data
covered _for the decay
a two-year-per4od heat removal pumps
which .
- -
included quarterly testing of -five different Jumps. sThe data indicated
that the pumps were being tested as required )y the ASME Section XI code
and that the pumps met the acceptance criteria in the surveillance
-
procedures. The team noted that the licensee was using the later
version of the ASME code, which removed the requirement for an alcrt
range and ex)anded the normal operation range for puma differential
pressure. T1e inspector noted that all of the pumps lad exceeded their
testing interval and needed to be tested prior to plant startup.
The team did note a-few attention to detail problems with the Section XI
test data. In one example, the operator documented that the DHP-1A motor
current was 28 amps: however, normal running current for the moter
during other testing was approximately 37 amps. In another example. the
operator documented that tie MUP-1A motor current was 40 amps: however,
normal running current for thc motor during other testing was
approximately 64 amps. In a third example, the operator documented the
pump flow at 2950 gpm for a DHP-1A test: however, the Section XI
differential pressure test needed to be performed at 3000 gpm. Although
these problems did not significantly affect the surveillance testing.
they indicated a problem with attention to detail.
The team also noted that the licensee did not have a working program for
trending pump and valve performance data. The licensee was in the
process of purchasing a software data base and downloading the pump and
-valve data. In the future this could provide a reliable means for
trending pump and valve performance and implementing a predictive
maintenance program.
c. Conclusions
The ASME Section XI pump testing of the decay heat removal and makeup
and purification systems was found to be acceptable.
4
A negative observation was made due to problems with attention to detail
while performing surveillance testing.
. .
..
..
.
.
.
_ _ _ _ _ _ _ - _ .
_ .
.
. - _ _ _ _
. .
47
A negative observation was made for not having a pump and valve trending ,
program.
E2.3 Evaluation of Probabilistic Safety Assessment (PSA) Issues Asso.gjgttd
with Makeuo and Purification System and DeCav Heat Removal System
a, Insoection Scoce (93801)
~ ~~
The team reviewed the results of the plant's PSA status with licensee
representatives. The team focused on results of the PSA relating to the
makeup and purification and decay heat removal systems,
b. Observations and Findinas
Team members met with the licensee's representatives to discuss the PSA
,. on October 7. 1997. The. team.noted that the licensee;su ndividual Plant. .
- - -
Examination (IPE). submittal as requested by NRC Gener.ic Letter 88-20 was
under review by the NRC staff. Therefore, no evaluation was made
relating to the quality of the PSA, However, the team did note that the
- licensee was using the results of the PSA to evaluate risk associated
with the makeup and 3urification and decay heat removal systems. No
plant modifications las been identified for these two systems based on
the PSA. The licensee had identified a procedural change based on the
PSA for the plant Emergency Operating Procedures. The team noted the
Emergency Operating Procedure had been changed based on this issue.
c. Cr lusions
The team determined the licensee had a Probabilistic Safety Assessment
model for Crystal River Unit 3 and had changed an Emergency Operating
Procedure based on PSA information.
x E3 Engineering Procedures and Documentation
E3.1 Desian and Licensina Basis Reviews Associated with Makeuo and
Purification System and Decay Heat Removal System
a. Insoection Scone (93801) ,
The team evaluatd the FSAR sections and enhanced design basis documents
(EDBDs) related to the selected systems and interfacing systems and the
associated electrical and I&C systems.
(
b. Obervations and Findinas
The team identified a discrepancy in FSAR Table 6-19. item 5 under the
column " Adequate Flow Achieved by" in which it indicates for a -
postulated HPI Line Small Break LOCA coincident with a loss of off-site
power and a failure of a 4160V/480V ES Transformer that adequate flow
would be achieved by 3 lines and 2 pumps and no operator action was
'
required. However, after this statement in parenthesis it describes
operator action to regain 1 or 2 intact injection lines by switching the
__
_ _ _ _ _ _ _ _ _
'
4
48
)ower source for the salves. Further, under the column " Injection Lines
_ cst" it indicated that 2 of the 4 injection lines would be lost as a
result of the failure of the 4160V/480V ES Transformer. So that 3 lines
wouid not be available to inject without operator action to switch the
power sources for the valves. The team concluded that the FSAR was not
exactly correct in identifying that "no operator action is required" to
n.itigate this event. This issue was discussed with the licensee and a
Precursor Card (3-C97-7271) was initiated to document the problem and to
implement corrective action,
c. Conclusions
The Enhanced Design Basis Documents and the Final Safety Analysis Report
(FSAR) were adequate for the selected systems; however, one discreaancy
was noted in the FSAR regarding required operator action for a h g1
. pressure-injection 1.ine break small break _os; of Coolant, Accident.
E4 Engineering Staff Knowledge and Performance
-
E4.1 Evaluation of the Safety Assessment Process Relatina to Decay Heat
Removal System Valve Position Confiaurations
a. Insoection Scooe (93801)
The team reviewed the decay heat removal system flow diagrams and
evaluated valve position configurations with the design basis docummnts,
b. Observations and Findinas
The team revitled decay heat removal system Flow Diagram (FD)-302-641.
DECAY HEAT REMOVAL. Revision 42, and noted that the motor operated
suction valves (DHV-34 and DHV-35) for the two flowpaths from the
Borated Water Storage Tank (BWST) to the suction of the decay heat pumps
a)peared to be shut during normal plant cperation. The team reviewed
t1e " ENHANCED DESIGN BASIS DOCUMENT FOR THE DECAY HEAT SYSTEM." Revision
7 and noted that the component parameter information for DHV-34 and DHV-
35 identified that the valves "must be open within 25 seconds and are
required to be normally closed." The REASON /SO
stated in part. " . valves must be normallyosed cl,URCE part of Rthe document
per A)pendix
commitments." Team members met with the licensee on Octo)er 9. 1997
and discussed the position configuration of DHV-34 and DHV-35 during
normal operations. The team informed the licensee they considered the
Josition of normally shut to be different from configurations that had
Jeen encountered at other plants. The normally shut position required
the valves to open during loss of coolant accidents. The licensee
stated that DHV-34 and DHV-35 were normally closed so that a spurious
operation due to a fire of one valve in the flowpaths between the BWST
and the containment sump would not allow the BWST to gravity drain to
the sump. The team requested additional information relating to the
justification for positioning the valves in a closed position based on
the Appendix R requirements.
_ _ _ _ _ _
_ _ _ - - _ _ ,
.. .
49
On October 22. 1997, the team became aware of PC 96 4572 which
identified "en ap)arent discrepancy in docketed correspondence regarding
the normal "stanci]y" position of DHV-5. DHV-6. DHV-34, and DHV-35." The
team requested information relating to this PC and was provided the
information on October 23, 1997. Additional information was requested
and provided after the team left the plant on October 24, 1997. The
licensee provided further information including a 1985 safety evaluation
which supported the procedure change to position DHV-34 and DHV-35 in
. _
the closed position during normal operation.
The team continued their review of licensee documentation associated
with this issue during the week of October 27 - 31. 1997. A review of a
licensee interoffice correspondence memorandum from Nuclear Licensing
No. NL96-0122. Subject: " Licensing Basis Review for DHV-5 & 6 and DHV-34
& 35 in Support of the LPI Project Team." dated September 24. 1996.
. .. concluded, in part "DHV-34 and DHV-35 were original.ly: configured as .
-
.- normally closed valves. FPC revised OP-404 to maintain these valves in
the open position to comply with NRC recommendations. ~However. in 1985
FPC decided to close DHV-34 and DHV-35 based on Appendix R work.
-
Keeping DHV-34 normally closed would prevent dumping the BWST to the RB
sump in the event of a fire that resulted in repositioning DHV-42 open.
It is not clear if a safety evaluation was performed to support these
valves being normally closed in light of previous correspondence with
the NRC." The team reviewed other licensee interoffice correspondence
memorandums from Nuclear Operations Engineering (N0E) uiscussing the
subject valves. N0E97-0031. Subject: " Opening of DHV-34/35 to preclude
possibility of water hammer DXREF: PR96-0401. CAP Step 15" dated
January 14, 1997, discussed a N0E position that "DHV-3t./35 should be
normally open to preclude the potential for a water hrnmer." N0E97-
0527. Subject: " Opening of DHV-34/35 to preclude possibility of water
hammer DXREF: PR96-0401. N0E97-0031." dated May 15, 1997, discussed a
MAR 97-03-03-01 which installed vent valves on the bypass lines around
DHV-39 and DHV-40. The document stated "...the use of these vent valves
' will eliminate the water hartner potential from occurring and makes the
i determination of the normal position of DHV-34/35 an operational
preference for plant system lineups." It further stated. "...since a
engineering issue no longer exists for determining the normal position
- for DHV-34/35. fu-ther inaut for their normal p,osition and related
A)pendix R requirements s1ould come from Operations." The team reviewed
t1e safety evaluation for the procedure change to OP-404 which was made
in 1985 and_ concluded the safety valuation was inadequate. The team ._
considered the licensee had not conducted an adequate 10 CFR 50.59
< review of this issue as of October 24. 1997. In addition, the team's
evaluation of this issue relating to the requirements of 10 CFR 50.59
determined that a potential unreviewed safety question existed.
Specifically, the team considered the arocedure change made to OP-404 in
1985, which required the positions of JHV-34 and DHV-35 to be closed
during normal operation. was an unreviewed safety question because the
procedure change created the possibility for a malfunction of a
different type than any evaiuated previcusly in the safety analysis
.
_ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ . _
.
. - . .
,
.- .
L 50
report, . The team also considered that other documentation that was
reviewed did not adequately disposition the issue of required position
status of DHV-34 and DHV 35 during normal operation.
The team noted that the licensee and the NRC had recr'aized past
problems in the licensee's Engineering organization relating to 10 CFR
50.59 evaluations. The NRC issued violations with Civil Penalties for
these problems as part of inspection activities documented in Inspection
~ ~
, Reports 50-302/95-22, 96-12 and 96 19. Licensee cerective actions for
'these problems had been completed and were being reviewed by the NRC
during the SSFI inspection period. The team noted that although the
licensee had identified the issue in September 1996. no active precursor
card or issue was identified to resolve this significant condition
adverse to quality. The team was provided a 7py of problem report 96-
0401 on November 6. 1997. This problem report listed an action item to
, m. .. 3repare-a safety evaluation to support the valve alignment of DHV-34 and
- --
)HV-35. The proposed completion date for the safety-evaluation was
March 1. 1997. iowever, this item had not been performed as of
November 6, 1997. Discussions between the team leader and Crystal River
-
Management on November 6.1997, lead to the conclusion that the safety
evaluation would not have been completed prior to unit restart.
Code of Federal Regulations 10 CFR 50. Appendix B. Criterion XVI
requires, in part. that measures shall be established to assure that
conditions adverse to quality are promptly identified and corrected. In
the case of significant conditions adverse to quality, the measures
shall assure that the cause of the condition is determined and
corrective action taken to preclude repetition. A violation is
identified (50 302/97-1413) for Failure to Take Adequate Corrective
Actions to Identify and Correct the Design Weaknesses-Associated with
Adequacy of the Past 10 CFR_50.59 Review for Positioning of DHV-34 and
DHV-35 During Normal Operation.
c. . Conclusions
A violation was identified for failure to take adequate corrective
actions to identify and correct the design weaknesses associated with
adequacy of the past 10 CFR 50.59 review for pqsitioning of DHV-34 and
DHV-35 during normal operation.
E7.1 Review of Ooen Items Trackina of Partially Clos'ed Modifications
a. Insoection Scooe (93801)
The team reviewed the licensee's process for disposition of partially
closed modifications and looked at documentation associated with three
partially closed modifications for the decay heat removal and makeup and
purification systems.
.
- _ - _ _ _ - _ _
_ _ _ _ _ _ _ - - _ _ _ _ _ - - - - - - _ . - _ _ _ _ - - ,
I
l
l , o
51
b. Observations and Findinos
During the inspection period, the team became aware of an issue the '
licensee was reviewing associated with disposition of partially
installed modifications. The team discussed this issue with the
licensee personnel involved in the review. Three Modification Aparoval
Records (MARS) were identified which had open items outstanding w1ich
required closeout prior to the MAR packages being closed out. The team
reviewed the outstanding open items for the following MARS.
. MAR 92-04-02-05 " Decay Heat & Makeup Valves DHV-39, 40. MUV-3.9
Operator Modifications " dated May 28. 1992
. MAR 95-10-02-01, "MUP-2A/2B/2C AUTO START," dated October 17. 1995
. . . MAR 95-01-07-04. "MUVe64 INDICATION." dated October.12. 1995 .
-
-
.
. . . -
Examples of open items included stocking of spare parts, procedure
revisions, etc. The team concluded the open items for the partially
-
completed MARS reviet ed did not create any operational issues.
c. Conclusions
The team concluded the licensee was adequately managing open items
associated with partially installed modificotions.
Team members assessed the licensee's performance relative to the design
control process in four of the five areas of continuing NRC concern:
1) Management Oversight --- Adequate
2) Engineering Effectiveness --- Adequate
3) Knowledge of the Design Basis --- Adequate
4) Compliance with Regulations --- Adequate
5) Operator Performance --- Not Assessed
IV. MANAGEMENT MEETINGS
X1 Exit Meeting Summary ,
The team leader discussed the progress of the inspection with licensee
representatives on a daily basis and presented the inspection results to
members of licensee management and staff listed below at the conclusion
of the inspection on October 24, 1997. An additional exit meeting was
held by telephone to present the ir,spection results associated with
positioning of valves DHV-34 and DHV-35 during normal operation on
November 6, 1997. The licensee acknowledged the findings presented.
The team leader asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
information was identified.
_ _ _ _ _ - _ _ _ _ _ _ _ .
____ _
. *
52
PARTIAL LIST OF PERSONS CONTACTED
LICENSEE:
J. Baumstark, Director. Quality Programs
J. Cowan Vice President. Nuclear Production
R. Davis, Assistant Plant Director. Operations
M. Donovan Supervisor, Nuclear Plant Technical Support
~
- J. Holden. Site Director
~J. Lind, Manager, Nuclear Operator Training
R. McLaughlin, Senior Nuclear Regulatory Specialist
C. Pardee. Director, Plant Operations
- W. Pike Manager Nuclear Regulatory Compliance
- M. Rencheck, Director. Engineering
M. Schiavoni, Assistant Plant Director, Maintenance
. . D.. Shook. Nuclear Staff Engineer. .
=f- . . .
-
J. Terry, Manager, Nuclear Plant Technical Support - 1 ._,
NRC:
.
- S. Cahill, Senior Resident Inspector
T. Cooper, Resident Inspector
J. Jaudon, Director. Division-of Reactor Safety
- K. Landis. Chief. Branch 3, Division of Reactor Projects
S. Sanchez, Resident Inspector
M. Thomas, Senior Reactor Inspector
- Licensee and NRC personnel involved in the telephone exit with the SSFI
team leader on November 6, 1997.
LJST OF INSPECTION PROCEDURES USED
IP 61726 SURVEILLANCE OBSERVATIONS
IP 62707 -MAINTENANCE OBSERVATTC%
IP 71707 PLANT OPERATIONS
IP 93801 SAFETY SYSTEM FUNCTIONAL INSPECTION (SSFI)
LIST OF ITEMS OPENED AND DISCUSSED
50-302/97-14-01 IFI Review of Operational Procedurcs Prior to
Restart (Section 03.1)
50-302/97-14-02 VIO Failure to Assure that Conditions Adverse to
Quality Are Promptly Identified and Corrected
(Sections M2.1 and E1.5)
50-302/97-14-03 IFI Followup on Verification of ASME Section XI
Valve Testing (Section M2.4)
50-302/97-14-04 VIO Failure to Adequately Test HPI Valves MUV-23.
24. 25. and 26 Power Selector Switches (Section
M2.6)
-.
_ __ - ___ _.
.
.
- . . .
. .
53
50 302/97-14-05 VIO Failure to Provide Adequate Procedure for
Calibration of Reactor Vessel Level
Instrumentation for Reduced Inventory Operation
-(Section M2.7)
50-302/97-14-06 VIO Failure to Evaluate Out-of-Tolerance M&TE
(Section M3.2)
~ ~~
50-302/97-14-07 VIO Failure to Follow Foreign Material Exclusion
Procedure Requirements (Section M4.1)
50-302/97-14-08 URI NRC Evaluation of Acceptability of Thermal
Expansion Chambers for Containment Penetratior.
Line Modifications for GL 96-06 (Section E1.2)
. . 50-302/97-14-09- URI NRC Evaluation of AcceptabiMtf<of Makeup System .
- - . -
Trains-Crosstied Without Ability;to. Remotely
Isolate Trains (Section El.3)
-
50-302/97-14-10 IFI NRC Followup that Licensee Approach for
Resolution of Deficiency Associated with Lack of
Documentation for Original Piping and/or Support
Calculations is Acceptable (Section El.4)
50-302/97-14-11 VIO Overload Relays Not Installed as Automatic Reset
as Stated in FSAR (Section E1.5)
50-302/97-14-12 URI NRC Review of Licensee Response to GL 88-17
Associated With Reduced Inventory Operation
(Section E2,1)
50-302/97-14-13 VIO Failure to Take Adequate Corrective Actions to
Identify and Correct the Design Weaknesses
Associated with Adequacy of the Past 10 CFR
50.59 Review for Positioning of DHV-34 and DHV-
35 During Normal Operation (Section E4.1)
,
e
-._ _ _ __.____ _
_ -_
. .
54
Appendix A
LIST OF DOCUMENTS REVIEWED
LIST OF INDUSTRY INFORMATION DOCUMENTS REVIEWED
ISA-567.04. Par; I. "Setpoints for Nuclear Safety-Related Instrumentation."
dated September 1994
-
'
ISA RP67.04. Part 11. " Methodologies for the Determination of Setpoints'for
Nuclear Safety-Related Instrumentation." dated 1994
NRC Generic Letter 95-02 "Use of NUMARC/EPRI Report TR-102348 'Gaideline on
Licensing Digital Upgrades.' in D2termining the Acceptability of Performing
Analog-to-Digital replacements Under 10 CFR 50.59," dated April 26. 1995
m..
-
, .. . .. .
. .
-
NRC Regulatory Guide 1.105 " Instrument Setpoints for Safety-Related Systems."
Revision 2. dated February 1984 .
-
NUMARC/EPRI Report TR-102348 " Guideline on Licensing Digital Upgrades" dated
December 1993
LIST OF DRAWINGS REVIEWED
B-208-026. EF-24. Revision 1
B-208-026. Elementary Diagram Index for Emergency Feedwater System,
Revision 11
B-208-028. ES-A58. Electrical Diagram of Engineered Safeguards, Revision 9
B-208-028. ES-B58. Electrical Diagram of Engineered Safequards. Revision 8
B-208-028 ES-A29. Elementary Diagram Engineered aafeguards. Revision 13
B-208-041. Electrical Drawing Index. Revision 11
B-208-041. Make-up Isolation Valve to Reactor Inlet l,ines Loop A. Revision 16
B-208-041, ML'-16. Elementary Diagram MU 150. VLV. To Reactor Inlet Lines Loop
A (HUV-27) ES & Shutdo,m MCC 3AB, MTMC-7 Revision 16
B-2Cd-041. MU-18. E?ementary Diagram Boratcd Wtr. Stor. Tank to MU Pump MUV-73
Engineered Safeguarcs MCC-3A3. MTMC-21. Revision 16
B-208-041. MU-20. Elementary Diagram H.P. Injection Control Valve To Reactor
Inlet Lines Loop A (MUV-24) Revision 15
B-208-041. MU-23. Elementary Diagram Reactor Coolant PP. Seal 150. VLV. (MUV-
18) ES & Shutdown MCC-3AB, MTMC-7, Revision 12
1
,, _ - - - - - - - - - - - - - - -
. i
55
B-208-041. MU-24. Elementary Diagram Makeup PP Recirc V. 3B MUV-257 Eng'd
Safeguards MCC 382. MTMC-6. Revision 12
B-208 041. MU-56. Elementary Diagram H.P. Injection Control VLVS. MUV 23 & 24
ESF Source Selector Switches. Revision 0
B-208-041. MU-57. Elementary Diagram HP Injection Contro'l VLVS MUV 25&26 ESF
Source Selector Switches. Revision 0
~~~
B-208-041. MU-59. Elementary Diagram Makeup Pump Discharge Crossover Valve
(MUV-9) Reactor MCC 3Bl. MTMC-2. Revision 7
B-208-050. RW-01. Elementary Diagram NOR. Nuclear Services Sea Water PP (RWP-
1) 4160V Unit Bus 3A. Revision 7
. _. B-208-050. RW-02. Elementary Diagram Emergency Nuclear Ser-vice Sea Water PP 3A
--
- (RWP-2A) 4160V ES Bus 3A. Unit 3A6 MTSW-2C. Revision 16 -
_ . _ .
B-208-050. RW-03. Elementary Diagram Emergency Nuclear Service Sea Water Pump
-
3B (RWP-2B) 4160V ES Bus 3B MTSW-2E-3B9. Revision 25
B-208-050. Rw-04. Elementary Diagram Decay Heat Sea Water PP 3A (RWP-3A) 4160V
ES BUS 3A. Unit 3A5 MTSW-2C. Revision 14
B-208-050. RW-05'. Elementary Diagram Decay Heat Sea Water PP 3B (RWP-3B) 4160V
ES Bus 38. MTSW-2E-3810. Revision 16
EC-206-011. Electrical One Line Diagram Composite. Revision 41
EC-206-041. Electrical One Line Diagram Vital 120V AC & Reg Inst 120V AC.
Revision-16
EC-206-052. Electrical One Line MCC Reactor 3Al AUX. BLDG Elev 143' - 0".
Revision 18
'
EC-206-053. Electrical One Line MCC Reactor - 3B1 AUX BLDG 143' - 0",
Revision 15
EC-206-055. Electrical One Line MCC ES-3A2 AUV. BLDG'119' - 0". Revision 19
EC-206-056. Electrical One Line MCC ES 381 AUX BLDG l'19' - 0". Revisions 17.
18. 19 and 28
EC-206-057 Electrical One Line MCC ES 3B2 AUX BLDG 95' - 0". MTMC-6.
Revision 15
EC-206-058. Electrical One Line MCC ES 3AB AUX. BLDG 119' - 0". Revision 18
(C-206-073. Electrical One Line Motor - Control Center MUV-23/24 and MUV-
c6/26. MUMC-1 and MUMC-2. Revision 5
. -
. -
. - . . . .
. .
'c
56
.
EC 206 074 Electrical One Line Diagram 480V MCC ES 3A3 AUX BLDG 119' - 0.
HTMC-21. Revision 14
EC-206 075. Electrical One Line Diagram 4B0V MCC ES 3B3 AUX BLDG 95' - 0".
Revision 1-
EC 209 023.-Sheet DP-01. Electrical Interconnection Wiring Diagram DC System
Battery Charger 3A DPBC-1A Revision 7
EC-209 023. Sheet DP-02. Electrical Interconnection Wiring Diagram DC System
Battery Charger 38 DPBC 18. Revision 8
EC-209 023. Sheet DP-03. Electrical Interconnection Wiring Diagram DC System
Battery Charger 3C DPBC-1C. Revision 7
. .. EC-209 041 MU 10.. Electrical Interconnection. Wiring Diagram: Makeup &. .
- Purification Valves MUV-18 & MUV 257,- Revision 9 . m_.._.
EC-209127. Sheet 3, Electrical Interconnection Wiring Diagram 480V Control
- Center Engineered Safeguard 3B2 Revision 15
FD 302 001. Sheet 1 of 1. Symbols. Revision 36
FD 302-082. Emerqenry Feedwater System Flow Diagram, Sheet 1 of 3, Revision 52
FD-302-641. Decay Heat Removal System Flow Diagram. Sheet 1 of 3. Revision 62
FD-302-641. Decay Heat Removal System Flow Diagram. Sheet 2 of 3. Revision 52
FD 302 641, Decay Heat Removal System Flow Diagram. Sheet 3 of 3. Revision 43 )
FD 302-661. Make up and Purification System Flow Diagram. Sheet 1 of 5.
Revision 54
FD 302-661. Make-up and Purification System Flow Diagram. Sheet 2 of 5.
Revision M
FD-302-661. Meke-up and Purification System Flow Diag, ram. Sheet 3 of 5.
Revision 60
FD-302-661. Make-up and Purification System Flow Diag' ram. Sheet 4 of 5.
Revision 64
FD 302-661. Make up and Purification System Flow Diagram Sheet 5 of 5.
Revisions 60 and 62
SS-201-063. Electrical Arrangement 120V AC Vital Bus 3R v50P 4. Revision 41
SS-201 071. 125 Volt DC Power. Revision 2
-
. *
57
LIST OF PROCEDURES REVIEWED
Surveillance Procedure SP 457. " Refueling Interval ECCS Response To A Safety
injection Test Signal." Revision 14
Surveillance Procedure SP 457A. "ECCS Response To A Safety injection Test
Signal (Mode 1 3)." Revision 1
~
Nuclear Engineering Procedure NEP 210. " Modification Approval Records."
~
Revision 18
NEP-235. " Design Considerations For Motor Operated Valves." Revision 4
NEP-253 " Preparation and Control of a Document Change Notice." Revision 12
. . 0ES 02." Analysis / Calculations Expectations." dated 1997 . a.. .
- -
1 .-,
MP-131A. " Maintenance of Decay Heat Pumps." Revision 6
- SP-340C, "MUP 1 A MVP 1-B. and Valve Surveillance." Revision 14
CP 146 "M&TE Calibration and Control." Revision 2
SP 169E. " Makeup System Instrumentation Calibration." Revision 7
NEP-135. "Use and Control of Computer Software." Revision 5
NEP 213. " Design Analyses / Calculations." Revisions 11 and 12
NEP 261 " Design Verification " Revision 5
PT 444 "High Pressure Injection Flow Verification Test Revision 1
Crystal River Unit 3. "l&C Design Criteria for Instrument loop Uncertainty
Calculations." Revision 2
MP-171. " Filling and Venting Of Differential Pressure Transmitters and
Devices." Revision 5 ,
CP-116A. " Foreign Materials Exclusion (FME) Control,". Revision 4
CP-111. " Processing Of Precurser Cards For the Corrective Action Program."
Revision 60
SP-175. " Containment Sump Level and Flood Monitoring System Calibration."
Revision 24
SP-144A, "RCITS Reactor Vessel and Hot leg Level Channel Calibration. "
Revision 12
SP-195. " Remote Reactor Vessel Level Instrument Calibration." Revision 4
.. ..
._ _ _ _ _ _ _ _ - _
. .
58
SP 162 " Post-Acciderit Monitoring Instrumentation Channel Calibration."
Revision 31
SP 169G. "Make-Up Tank Instrumentation Calibration." Revision 0
,SP 435. "Valvo Testing During Cold Shutdown." Revision-45
SP-306. " Weekly Surveillance Log." Revision 14
' ~'
SP-301. " Auxiliary Building Shutdown Log Readings." dated October 7.~1997
SP 320. " Availability of Boron Injection Sources and Pumps." Revision 67
1
SP-340B. "DHP-1A-DSP 1A and Valve Surveillance." Revision 32
.< -
-
- SP 340E. "DHP-18-DSP.-18 and Valve Surveillance." Revision..;.-166
-
-
.
. .. . -
SP-340C "MUP-1A MVP-1B and Valve Surveillance " Revision 16".
-
SP-340F. "MVP-lc and Valve Surveillance." Revision 15
0P-700F. "120/208 V Heat Trace Distribution Panel." Revision 9
Al 400C "New Procedures and Procedure Change Processes." Revision 22
Al-400G. ' Procedure Writing Reference Manual." Revision 2
Al-402A " Writer's Guide For Abnormal And Emergency Operating Procedures."
Revision 8
Al-402B, " Procedure Writing (Except For APs E0Ps, and TPs)." Revision 16
Al 605 " Condition Monitoring Program." Revision 1
AR 302. "ESB Annunciator Response." Revision 18
AR-702. "SSF0 Annunciator Response.1 Revision 14
'
01-02. " Shift Routines and Operating Practices." Revision 2
01-07. " Control Of Equipment And Systems." Revision 6
OP-402. " Makeup And Purification System." Revisions 91 through 94
OP 404. " Decay Heat Removal System." Revisions 106-through 109. Draft 110
PM 1788. " Preventive Maintenance Of Limitorque Actuators (6) Year Inspection."
Revision 4
'
ROT-4 52 " Makeup And Purification System." Revision 11
ROT-4 54 " Decay Heat Removal." Revision 10
,
- _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ __ _ _ _ _ _ - _ _ _ _ _ _ _ _ .___ _
. .
59
SP-300. " Operating Daily Surveillance Log." Revision 139
SP-338. " Remote Shutdown And Post Accident Monitoring Channel Check.'
Revision 26
LIST OF DESIGN BASIS DOCUMENTS AND CALCULATIONS REVIEWED
Crystal River Unit 3. " Enhanced Design Basis Document for the Decay Heat
System." Revision 7. dated June 4. 1997
Crystal River Unit 3. " Enhanced Design Basis Document for the Makeup and
Purification System." Revision 8. dated August 1.1997
FSAR Section 6.1, Emergency Core Cooling System (ECCS). Revision 23
. FSAR Chapter 8. Electrical Systems. Revision 23 J. - .
FSAR Section 9.1 Makeup and Purification System. Revision 23-
-
FSAR Section 9.4. Decay Heat Removal System. Revision 23
FSAR Section 9.5. Cooling Water Systems. Revision 23
E 90 0035. Overload Protection Calculations For ES MCC 3A3. Revision 0
E-90 0031. Overload Protection Calculations For MCC ES 3B2. Revision 6
E-90-0030. Overload Protection Calculations For MCC ES SA2 Revision 5
E-90-0073. Overload Protection & Breaker Trip Setpoint Calculations For
Selected MOVs. Revision 1
E 90-0032. Overload Protection Calculation For MCC ES 381. Revision 10
E-91-0020. Safety Related AC Power Cable Evaluation. Revision 0
E-91-0021. Safety Related Load Evaluation. Revision 0
E-92-0036, 480V ES MCC Overload Element Undervoltage Ivaluation. Revision 2
E-90-0033. Overload Protection Calculations For MCC ES 3AB. Revision 9
E-90-0109. Protective Relay Settings Calculations for 4.16 KV Unit /ES Buses.
Revision 0
E-90-0078. 480V Systems Protective Devices Coordination Study Bus 3A Tag MTSW-
3F.-Revision 2
E-90-0079. 480V Systems Protective Devices Coordination Study Bus 3B Tag MTSW-
3G. Revision 1
. . . . . . . .
. .
60
E-91-0026. Emergency Diesel Generator "A" Loading Evaluation. Revisions 0. I
and 2 and a Preliminary copy of Revision 3
E 91 0027. Emergency Diesel Generator "B" Loading Evaluation. Revisions 0. 1
and 2 and a Prelimina_ry copy of Revision 3
E-91-0018. Transient Motor Start / Voltage Drop Analysis During Load / Post BL.
Lo*d Revision 1
'
~ E-90'0077. CR3 Voltage Drop and Load Flow Analysis. Revision 2
E-90-0029. Overload Protection Calculations For ES MCC 3A1 Revision 1
E 90 0036. Overload Protection Calculations for ES MCC 3B3, Revision 2
, ., I 91 0012. BWST Level Accuracy,. Revision 3 -e-~
' '
l-97-0008. LPl Crossover Flow Loop Accuracy. Revision 0
- M90-0021. Building Spray and Decay Heat NPSH. Revision 9
M90 0023. Reactor Building Flooding. Revision 5
M90-0033. Decay Heat Cooler Design Pressure Upgrade. Revision 0
M96-0006. MUT Vapor Pressure Evaluation. Revision 0
M94-0053. Allowable MUT-1 Indicated Overpressure vs. Indicated Level..
Revision 5
M95-0044. RW/DC/DH Thermal Analysis-DC System Temperature Calculation.
Revision 0
M96 0025 HPI System Setup Requirements for PT-444. Revision 0
M96-0039 CR-3 HPl Pump H-Q Response, Revision 0
M97-0053 MiscellaneousHPISystemFlowAnalyses. Revision 0
M97-0088 Hydraulic Analysis for LPI Hotleg Injection.to RCS, Revision 0
<
M97-0097 Low Pressure Auxiliary Spray Flow Rate for Boron Precipitation.
Revision 0
S96-0098 Justification for CR 3 Pressurizer due to HPI Test,s. Revision 0
Electrical Design Criteria EDC-4. Motor Overload Protection. Revision 3
Electrical Design Criteria. Electrical Circuit Physical Separation and Cable
Tray Loading. Revision 4
_ _ _ _ _ _ - - _
_ - _ . _ _ _ _ _ _ _ _ . . - _ _ _ _._ _ _ . _ . _ ._ _ __. . _ _ _ _ _ _ _ _ _ _
, ,
61
Electrical Calculations Organization and Maintenance Process, dated June 25,
1997
Vendor data sheet on Gould ITE Industrial Control Overload Relays. Class L10
and Lll, (page 140)
50,49 Walkdown data sheets for DHV 41 and MUV-58 dated June 5. 1992, and May
'
10. 1990, respectively
i
LIST OF MODIFICATIONS REVIEWED
4
MAR 95 09 04-01 "BWST Narrow Range Level." dated December 13, 1996
MAR 97-06 21 01 " Replacement of DH 38 dPT & DH-38-FII," dated October 4. 1997
j, MAR 91-02-02-01, " Resolution of 480V MCC Open items." FCN 41or3r dated March 9.
-
1992 .._
i
LIST OF SYSTEM READINESS REPORTS REVIEWED
.
" Decay Heat Removal System. Initial Report - Phase 1 Results " dated June 4
1997
i
t
" Makeup System, Initial Report - Phase 1 Results." dated May 29. 1997
!
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Reasonable assurance thal CR-3 will
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CR-3 can Mitigate all Design Basis Accidents
Modifications System Configuration
& Focused Readiness Document
_
Review Review ..
.
Integration
of Programs Program T Project
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- A PROGRAM OVERVIEW
9
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_ _ - - _ - . . _ . _ _ _ _ _ _ - -
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> Graded approach assessment of 105 systems
> Evaluation of results
> Disposition and track restart requirements
> Operations acceptance of systems
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IMPLEMENTATION ELKMENTS
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- - - - - - - -
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- Status of Assessments
i > Systems Completed
5 > Level i > Level 2
. Core Flood . Air Handling . Building Spray
f
-
. Decay Heat Systems . Chemical Addition
i . Emerg. Feedwater . Annunciator System . DC Electrical
. EFIC . Decay Heat Closed . Feedwater
Cycle Cooling . Electrical Systems
[ . -Eniergency Diese1
. Main Steam , . Nuclear Instruments
_ Generator
j . Engineered . RB Airlocks h . Rad Monitors
- Safeguards . Reactor Protection Sea Water
h Make-up and System
.
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Purification . Waste Disposal
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SYSTEM READINESS REVIEW PROCESS -
-- - -- - _. . . - - - _ - - . - - - - - - - .. -. .- . _ .
License Design Procedures Configuration
. i [ _ _ _ _ . . _ _ __
FSAR EDBDs Pr0C dur
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_. _ . _ . _ _ . _ _ _ _ a __ J _ _ _ _
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Commitments FS R
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, _ _ l_ _ _ _ __ __ _ i _
l' Notices /
CMIS Maintenance
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7
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Specifications ,,
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CONCLUDING SUMMARY
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>}SRR Process Identifies the : Issues.
>SRR Process drives Issueb to
closure.
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