ML20137T046
| ML20137T046 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 03/24/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20137S969 | List: |
| References | |
| 50-302-97-01, 50-302-97-1, NUDOCS 9704150302 | |
| Download: ML20137T046 (68) | |
See also: IR 05000302/1997001
Text
- _ _
_ . _ . . _ . _ - . _ _ . . . . _ _ _ _ - _ . _ _ _ _ _ __
'; f. '.
'U.S. NUCLEAR REGULATORY COMMISSION
REGION 2
1. .
1
. Docket No: 50-302
License No: ~0PR-72
Report No: 50-302/97-01
.
~ Licensee: Florida Power Corporation
Facility: Crystal River 3 Nuclear Station
Location: 15760 West Power Line Street
Crystal River, FL 34428-6708
Dates: January 12 through February 22, 1997
' Inspectors: S. Cahill, Senior Resident Inspector
T. Cooper. Resident Inspector
B Crowley, Reactor Inspector, paragraphs E2.1, E8.1,
E8.4 E8.10
P. Fillion, Reactor Inspector, paragraph E8.5
L Mellen Project Engineer, . paragraphs E8.4. E8.7
L. Raghavan, Project Manager. paragra)h E1.4
R. Schin Reactor-Inspector, paragrapis E1.3, E8.2,
E8.3
H. Thomas. Reactor Inspector. paragraphs E8.6, E8.8.
E8.9
Approved by: K. Landis, Chief. Projects Branch 3
Division of Reactor Projects
'
'
J.
9704150302 970324 N
PDR ADOCK 05000302 '?
G- PDR a
_ . . __ .__ _ _.
l
.;
l
!
EXECUTIVE SUMMARY
Crystal River 3 Nuclear Station
NRC Inspection Report 50-302/97-01 (
This integrated inspection included aspects of licensee performance in 5
operations, engineering.' maintenance, and plant support. The re) ort covers a. j
, 6-week period of resident inspection:-in addition, it includes tie results of !
- announced inspections by four reactor inspectors, the project engineer from
l- - Region II. and the NRR project manager. .;
I Ooerations
] Problems with inconsistent logging criteria and unclear and unenforced ,
'
. procedural expectations were observed by the inspectors in operations logs -
,
'
(paragraph 01.2). !
!
s
' A Violation (VIO 50-302/97-01-01) was' identified for clearance tagging .
1
-
recuirements which were inadequate to preclude personnel and equipment hazards !
. anc resulted in a valve being repositioned while under a red tag clearance 3
(paragraph 01.3). .
,
-
r
Several attention to' detail and poor process problems indicated that
- deficiencies could exist in the licensee's expectations and process for .
.
configuration and status control of plant equipment (paragraphs 01.3. 01.4. l
7- and 01.5).
A Violation (VIO 50-302/97-01-02) was identified for failure to follow
'- procedures, resulting in an inadvertent emergency diesel generator start. i
Contributors to this event, such as poor briefing and preparation of the
- operator, assigning the operator to extraneous tasks during the performance of
! a time sensitive evolution, and the operator failing to perform vital steps of ,
. the procedure are indicative of performance problems which still exist in l
1 plant operations (paragraph 01.6).
The licensee staff exhibited an adequate level of conservative decision making
and questioning attitude. Several good examples were observed but some poor
t examples continue to be found. Licensee management continues to emphasize
development of a conservative safety culture (paragraph 04.1).
Licensee self-assessment activities were being actively restructured in an
'
attempt to improve their effectiveness. Some change related problems were
observed due.to implementing new programs (paragraph 07.1).
E The inspectors concluded the new corrective action program was functioning
- adequately, but several deficiencies detracted from its effectiveness. The
licensee was actively working to improve the process and correct these
deficiencies (paragraph 07.2).
liaintenance
Several personnel errors and programmatic instrument calibration problems were I
identified as.a Violation (VIO 50-302/97-01-04) of Technical Specification
.
+ nor, +v, n ,, y - , , - , , . . , - . .. m + r.e -
a ,e +n - . , wt. , w- . , - - - -,e - +-
. . _ __ _ _ _ __
2
Surveillance Requirement 3.7.13.1 for spent fuel pool level verifications 1
(paragraph M1.1). ,
The decision to assess the maintenance controls of the plant computer was a
proactive initiative on the part of licensee management. The assessment
resulted in more stringent controls being implemented _ (paragraph M1.2).
Problems were encountered throughout the performance of the Emergency Diesel
Generator 1A outage. Lack of coordination was identified as a key
contributor. A weakness was identified for the absence of a mechanism to
ensure that tasks scheduled for the weekend that were not completed were
rescheduled for the subsequent week (paragraph M1.3).
A Non-Cited Violation (NCV 50-302/97-01-05) was identified for an inadequate
surveillance procedure to test the operability of the toxic gas chlorine
detectors (paragraph M1.5). 1
Weaknesses were identified with licensee work planning. Work packages were
planned for inappropriate plant conditions, were provided to field operators l
unfamiliar with the impact of the task. and were not thoroughly evaluated for ;
control impacts and updated to preclude future problems (paragraphs M1.6. i
M1.7).
Enaineerina
The inspectors observed good support from Technical Support system engineers
to Operations for emergent issues (paragraph E1.1).
A Non-Cited Violation (NCV 50-302/97-01-10) was identified for inadequate
design control. Non-Safety Related Components % Safety Related Applications -
Two Examples: Thyrite Surge Protection Device. Operator and Controller for
MUV-103. The licensee has taken the necessary immediate corrective actions
and has added final resolution of these issues to the restart restraint list
(paragraph E1.2).
An Unresolved Item (URI 50-302/97-01-06) was identified regarding concerns
with the design, licensing basis, and Technical Specifications for the high
pressure injection system. In addition, the inspector noted that the
licensee's recently completed extent of condition review (time line) for the i
makeup /HPI system design did not identify any of these concerns (paragraph
E1.3).
The inspectors noted improvement in the quality and thoroughness of 50.59 )
evaluations for recent engineering products over those generated one - two
years ago. However, the sample size reviewed was small and therefore, further
review will be required to verify improvements and acceptability of the
overall 50.59 program (paragraph E1.4). i
The licensee discovered problems with diesel generator test instrumentation l
inaccuracy that was not factored into surveillance testing requirements,
potentially rendering the diesel generators ino)erable. However, the
corrective action was timely and thorough rid t1e inspectors considered it an
l
_ . . - , __ . - _ . _ _ - . _ _ _ _ . _ _ . _ . . _ _ _ _ . . . _ _ _
c ;
'
f
e
];
'
3 ,
'!
,
. example of a problem found as corrective action for a previous problem f
.(paragraph E1.6). !
An error in' the FSAR was identified, where the FSAR stated-incorrectly that -
-
$
for a design basis accident the peak cladding temperature would exceed 2300 l
degrees F (the regulatory limit is 2200 degrees F). In addition.-the !
inspector noted that the licensee's current FSAR review project had not 1
identified this FSAR error (paragraph E1.1).
The inspectors noted that the licensee's definition of a design basis issue,
as defined in Procedures CP-111, CP-150, and CP-151 was not clearly broad
ii
enough to ensure that the requirements of 10 CFR 50, Appendix B, Criterion i
III: 10 CFR 50,72: and 10 CFR 50.73 would be met (paragraph E2.1). l
-The inspectors followed up on and closed a total of three violations and one l
Licensee Event Report (paragraphs E8.1. E8.2, E8.3). !
i
A violation (VIO 50-302/97-01-07) was identified for ' inadequate design control ;
-in that. design assumptions for Auxiliary Building temperatures used in the i
Environmental and Seismic Qualification Program Manual (ESOPM) and instrument i
loop uncertainty setpoint calculations were not properly translated into l
procedures for calibration of instruments, the Enhanced Design Basis Document,
cr the Final Safety Analysis Report. Additionally, there were no procedures
for ensuring the Auxiliary Building temperatures would be maintained withir;
the ranges. assumed by the ESOPM and instrument setpoint calculations and the,c
were no records of daily temperatures in the Auxiliary Building (paragraph
E8.4).
A violation (VIO 50-302/97-01-09) was identified for inadequate corrective
actions for cable ampacity (paragraph E8.5).
An Unresolved Item (URI 50-302/97-01-08) was identified regarding the adequacy
of procedures to take the plant from hot standby to cold shutdown from outside i
the control room in the event of a fire (paragraph E8.6). i
The inspectors noted that the licensee performed detailed evaluations and is
developing solutions for the issues identified in GL 96-06. Overall. the
Modification Approval Record package, including the'10 CFR 50.59 evaluation.
design, procurement, and installation of the containment penetration process
31 ping expansion chambers was detailed and well documented, demonstrating good
Engineering performance. One weakness was identified concerning completion of
the ISI Requirements check-sheet (paragraph E8.10).
P1 ant Sucoort-
On January 30. 1997, a second example of violation No. A(4)(01043) which was !
'
' issued'in EA 97-012 was identified by the creation of a penetration path into
the protected area via a breach in a condenser waterbox (paragraph 51.1).
A Non-Cited Violation (NCV 50-302/97-01-03) was identified for an inadequate '
fire system recirculation procedure. System recirculation flow limits were
not included in system procedures or the Fire Protection Plan, resulting in i
all . fire pumps inadvertently being rendered inoperable (paragraph F3.1). !
!
!
. . . . . - - - - = . . . = - . . - - - . .
. _ . . _ _ _ _ _ _ ._. ___. -. __
4
The inspectors assessed the licensee *s performance concerning the five areas of continuing NRC concern in the following
3aragraphs: the assessment is limited to the specific issue addressed in the respective paragraph.
NRC AREA 0F CONCERN ASSESSMENT PARAGRAPH
E1.2 E1.5 E1.6 E2.1 E8.1 E8.2 E8.3 E8.4 E8.5 E8.6 E8.7 E8.8 E8.9 E8.10
Management oversight G G G A G A G I A A G A' A G'
Engineering Effectiveness G G G G A G I I G G G A- G
Knowledge of design basis G G G I A G A G
Compliance With Regulations G fi G A G A G I I I G- G G G
l
operator Perfonnance G A i
5 - Superior G = Good A = Adequate / Acceptable I = Inadequate Elank = Not Evaluated /Insuf ficient Information
E1.2: 10 CFR 50.59 Safety Evaluations
E1.5: Decay Heat Valve (DHV) 21 Operability Evaluation
E1.6: Evaluation of Dranetz Test Instrument Inaccuracies on Emergency Diesel Generator Testing
E2.1: Corrective Action and Reportability Issues
E8.1: Corrective actions for Violation 50-302/96-05-05. Failure to Follow Procedures for Updating Design Basis Documents
E8.2: Corrective actions for violation 50-302/96-05-07 Inadequate Receiving Inspections for Battery Chargers; and ;'
.
'
Licensee Event Report 96-12-02. Operation Outside Design Basis Caused by Battery Chargers Having Inadequate Test
Results Accepted in Error
E8.3: Corrective actions for Violation 50-302/96-05-08. Failure to Follow Purchasing Procedures for Inverters
E8.4: EA 95-16. Use of Nonconservative Trip Setpoints for Safety-Related Equipment '
i
E8.5: IFI 96-201-13. Cable Ampacity Exceeded for DHP-1A [DCP-1A] Feeder Cable and Others
E8.6: Unresolved Item (URI) 50-302/96-201-04 Nonsafety-Related Positioners on Safety-Related Valves
E8.7: Inspector Followup Item (IFI) 50-302/95-15-01. Design Requirements for Nitrogen Overpressure .i
E8.8: VIO 50-302/96-09-07 Inadequate Corrective Action for Implementation of EFIC Task Force Recommendations
'
E8.9: VIO 50-302/95-21-03. Failure to Isolate the Class IE from the Non Class IE Electrical Circuitry for the Reactor
Building Purge and Mini-Purge Valves ,
E8.10: NRC Generic Letter 96-06. Assurance of Equipment Operability and Containment Integrity During Design- ;
-Basis Accident Conditions
- - - - . , - . . - - - - .. - .. . - . - - . . . -
..- - -- .-- - . - - _ , - . . - . . - . . . . - --- . - -
l
,
6
l l
Report Details
Summary of Plant Status J
The unit remained in Mode 5 throughout the inspection period, continuing in i
the outage that began on September 2, 1996. An outage on the "A" train of l
!
emergency core cooling system (ECCS) equipment was conducted to perform
corrective maintenance and implement a design change on the 1A Emergency !
'
Diesel Generator (EDG) to u) grade the EDG turbocharger nozzle rings and
replace the intercooler wit 1 a more efficient versico. These changes were i
expected to result in 150 kilowatts (Kw) of increased diesel capacity. The IB i
EDG will be upgraded during a pending "B" train outage'. The development of I
other modification packages continues, although no major modification began l
implementation during this inspection period. ]
.
I. Operatiom !
01 Conduct of Operations i
01,1 General Comments (71707) !
Using Inspection Procedure 71707 the inspectors conducted frequent
reviews of ongoing plant operations. Operators were professional in
that control room access was well controlled, communications were
normally thorough, and alarm response was good. The inspectors observed
several shift turnover meetings and observed that they were generally
formal and information was effectively communicated. Members of various
support groups such as the duty Technical Support system engineer
attended to support Operations needs.
As discussed in paragraphs M1.3 M1.6 and M1.7. the inspectors observed
several examples of inadequate communications and scheduling between
Operations and Maintenance personnel that resulted in challenges to the
operators and missed post-maintenance tests.
Housekeeping in the plant was routinely monitored and found to be
adequate although several examples of poor control of maintenance
equipment adjacent to 3rotected train components were identified by the
inspectors. None of t1e noted discrepancies comprised a significant
operational concern.
Overall, the inspectors observed some good examples of conservative
decision making and questioning attitude by plant operators as discussed
in paragraphs 01.4 and 04.1. However, several attention to detail and
poor process problems discussed in paragraphs 01.4. 5 and 6 below caused
the-inspectors to conclude that deficiencies existed in the licenses's
process for configuration and status control of plant equipment.
01.2 Operator Loas (71707)
The inspectors identified several significant items discussed elsewhere
in this report such as an inadvertent EDG start and a subsequent
-Operations investigation, a protected area security breach, and
mispositioned valves that were not logged in the Operations Shift ,
!
. _ - , , , . _ _ _ _ . , . . . , , . _ . _ . _ _ _ _ _ . , _ _ , _ , , _ _ _ _ _ _ _
_.. ._ , , , _ ,
_. . -.. . - .- - . .- - - . . . . _ . - - . -
,
h
,
2 !
Supervisor logs. The inspectors also identified equipment removed from
service such as Chill Water Pump 1A which was entered in narrative logs
but not in the Equipment Out of Service tracking log. The inspectors .
,
also observed inconsistencies between Shift Supervisor and Shift Manager
logs and between individual Shift Supervisors logs. The inspectors
reviewed 0)erations Instruction 01-5. Log Keeping. Revision 2. and
observed tlat several requirements were not clear and those that were
clear were not consistently enforced by management. Requirements such
as logging the time of turnover were not being implemented by Shift l
Supervisors on Duty (SS00) nor expected by management. Additionally.
-
practices such as recording log entry times versus event occurrence
times in the SSOD logs were not delineated in 01-5. The ins)ector
- observed that there was no guidance on the content of Shift ianager (SM) t
'
logs nor guidance on the coordination between the SM and SS00 logs, both
of which often contain the same content. The inspector discussed these
observations with Operations management who issued a Night Order. on r
February 4 clarifying management expectations for log entry thresholds.
The licensee incorporated these deficiencies in their revision to OI-5
being developed as an action for their Management Corrective Action Plan
II (MCAP). The inspectors concluded licensee management had not made
their expectations clear and had not held SS0Ds accountable to the ,
expectations in 01-5.
01.3 Valve Stroked While Red Taaaed Under a Clearance _. ,
a. Insoection Scooe (71707)
On February 6. 1997, condenser water box air removal (AR) valve ARV-1
was o)ened while red tagged under an active clearance which supported '
water)ox work. The inspectors evaluated the licensee's response to the
problem.
,
b. Observations and Findinas
Tagging Order 97-1-140 was issued to support mechanical work in the D [
waterbox of the main condenser. Tag R-008 was hung to require the main
~
control board switch for valve ARV-1 to be in the closed )osition. This
was the only point of control and the only tag hung for ARV-1 which was
an air-operated valve. On February 6 the instrument technician assigned
to perform work on the solenoid valve in the air supply line to the
valve operator for ARV-1 was directed to verify the failure mode of the
valve. The technician reported that ARV-1 failed open on loss of air. '
was not tagged, and was within the red tagged boundary of the mechanical
work clearance. Neither the technician nor SS00 was aware that ARV-1
was red tagged closed on the main control board. Consequently, the
technician was authorized by the SS00 to work on the solenoid. Although !
the control room operators recognized after the technician left that ,
ARV-1 was red tagged and they tried to page him, they were unable to ,
contact him and ARV-1 opened when he' started to work on the solenoid. !
The potential consequences were minimized because the technician,
although not required by procedure, had alerted the mechanical workers '
to exit the waterbox prior to his solenoid work because he knew ARV-1
,
_ . .
-- -. - .-. -. . - . . . . - -
[ , l
4 1
3
- ,
- workers. Nevertheless the inspectors were very concerned that a valve 1
"
was able to be opened when on an active clearance, was not tagged
~
, locally, and was a fail-open air-operated valve that was not gagged -
shut. The' licensee's clearance Procedure CP-115. Nuclear Plant Tags and
Tagging Orders, Revision 73, did not require local tagging of components
J or gagging of air-operated valves unless they were designated as. system 1
-
boundary valves Even then, CP-115 did not require tags on the J
- componentsmanihulatedtogaganairvalveorisolateandventthe i
- motive air. supply. The inspectors concluded these deficiencies l
4
constituted an inadequate. procedure which directly contributed to the !
ARV-1 event. Criterion V.of Appendix B to 10 CFR 50 . Instruction.
.
- Procedures and Drawings, requires in part, that activities affecting
quality shall be prescribed by documented _ procedures of a type ,
appropriate to the circumstances. Therefore, the failure of CP-115 to i
require local tagging of components and specify appropriate controls for
gagging of air-operated valves for red-tag clearances is a violation.
VIO 50-302/97-01-01, Inadequate Clearance Tagging Requirements.
- The licensee took thorough corrective actions the following day after
)lant management became aware of the event at their morning meeting.
iowever, the inspectors were concerned that the significance was not
- recognized by shift management at the time of occurrence, and
a)propriate actions were not implemented until almost 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later.
4
T1e inspectors also noted that the SS00 did not make an entry in his log
,
discussing the problems on the day of occurrence.. After managemelt !
initiated an Operations Investigation per Operations Instruction 12, !
Investigation of Abnormal Events Revision 1, a maintenance and tagging .
'
standdown was conducted that lasted three days. The event was briefed
to all available maintenance personnel, and approximately 120 tagging
orders were verified for adequacy. The licensee found numerous examples
that did not comply with CP-115 requirements or management expectations- i
these were documented on corrective action system precursor card (PC) !
. 97-0921. These included 27 examples of components that were system
boundaries but were not annotated as boundary valves on tagging orders, ,
ten examples of local control points not tagged, and two examples of air :
valves not in their fail safe position. The licensee also found that
different operators had varying methods of implementing identical
clearance orders. This indicated to the inspectors that CP-115 guidance
was not clear and that licensee management was not adequately overseeing
the process to ensure expectations were met and clearance orders were
consistent. The inspectors also reviewed CP-115 and concluded the
format was primarily an unprioritized listing of requirements which
contributed to the inconsistent implementation.
Licensee management was already concerned about a perceived negative !
- ' trend in tagging orders im)lemented per CP-115 and had initiated a root ;
- cause investigation under )C 96-5487 on December 5, 1996. However, this ;
i corrective action effort was assigned a due date of February 15, 1997, 4
'
- so it was not timely enough to preclude this event. The licensee
. incorporated their findings and corrective actions for the above
problems into the ongoing investigation. ,
,
4
4'
< e---m,
_ _ _ _ __ _. _ _ _ _ _ . . _ _ _ _ _ - _ _ _ _ _ _ _ _ - . ,
i
o
i
l
c. Ccnclusions ;
Although the inspectors determined the resultant safety impact of this :
event was minor, the potential exists for further violations of the l
integrity of the clearance program. The inspectors were very concerned !
i
that similar communications errors and program deficiencies could result
in a more significant hazardo'us situation. lhe inspectors considered. ,
these problems to be indicative of potential deficiencies in the l
licensee's overall process for configuration and status control-of plant ;
equipment. l
01.4 Ventina of Decay Heat Removal System (71707)- i
,
The inspectors observed that the Operations staff was concerned about :
previous problems ex)erienced with restoration of an out of service j
L decay heat removal ()H) system train. Upon opening the system isolation ;
valves between the DH system and the reactor coolant system (RCS). '
pressurizer liquid level had decreased several inches, indicating air
was introduced into the RCS. This occurred even though the DH system
had been properly vented per procedure. The Operations staff developed
new work instructions (WI) to augment the OH system venting process and
verify the amount and location in the RCS where the air collected. The ;
inspector witnessed the Plant Review Committee (PRC) review and approval
of these WIs. Although the inspector noted the lack of independent
verification in the restoration steps of one of the two Wis, the
inspector observed that the licensee effectively addressed concerns with
air accumulating in the reactor vessel head and developed conservative
guidance to assist the operators. The licensee's efforts were not
totally successful because 3ressurizer level still decreased upon DH
system restoration, althougl less than before. The licensee concluded a
new high point vent was recuired to effectively vent from under the j
system isolation valves anc included that as a restart item on their i
restart commitment checklist. PC 97-1052 and 1059 were generated to j
track resolution. The inspectors concluded that the missed independent j
verification was another example of potential deficiencies in the i
licensee's overall process for configuration and status control of plant
equipment. However, plant operators exhibited a conservative concern
and a good effort was made by the licensee to resolve it.
01.5 Miscositioned Valve Events (71707)
The inspectors reviewed the licensee's response to four examples of
mispositioned valves that occurred over a three day period. A raw water
system vent valve was inadvertently left open by an operator placing a
-heat exchanger-in service and was discovered after a pump start resulted
in water flowing from the valve A nitrogen system valve was found in
the incorrect position following maintenance activities. A makeup
system valve and station air valve were a)parently closed to isolate air j
leaks without any procedur91 controls. T1e licensee ap3ropriately
. recognized the overall impb cations of the combined pro)lem and
initiated a common root cause investigation. During the review the
inspector questioned the method of control and verification fcr root
l
l
1
l
-. .- - - - - _ - i
.. - -. -.- ---. --- . -- .-.-- . - -
.
5 l
,
isolation valves to instruments that are commonly operated by instrument
technicians. The licensee recognized that they did not have a procedure
to verify.the )osition of these valves to aneumatic valve controllers i
'
and initiated )C 97-0733 to implement furtler corrective action. The .
- licensee promptly issued an 0)erations Study Book entry to promulgate
the problems to operators. T1e licensee's investigation has revealed ;
that equipment alteration logs were not required to be retained as- ;
quality records for minor work packages. This made it impossible to i
, verify the last known position or. verification of several valves or l
components, hindering the licensee's investigation.- The licensee and
'
j
- inspector also recognized that management's expectations were to perform !
concurrent and independent verifications. These expectations were l
developed for previous mispositioning problems and were not being l
consistently implemented. .The licensee's common root cause was being i
finalized at the close of this Inspection Report period so their final ;
assessment and corrective actions will be reviewed in the next report !
4 period. .The inspectors considered these problems to be indicative of i
potential deficiencies in the licensee's overall process for I
configuration and status control of plant equipment.
l 01.6 Inadvertent Start of EDG-1 A .
- !
a. Insoection Scooe (71707. 40500) j
'
While performing the Modification Approval Record (MAR) functional test
restoration of EDG-1A at 9:18 p.m. on February 1.1997, during the
manual roll of the diesel to clear oil and moisture from the cylinders. !
the diesel inadvertently started and accelerated to full speed. Control !
room alarms were received for the automatic start of the diesel !
generator room fans. AHF-22A and AHF-22B. The control room operator was ;
called by the plant operator performing the restoration. who notified
him of the inadvertent start. A Senior Reactor Operator (SRO) and plant i
.
operator were dispatched from the control room to secure the diesel i
generator. ;
b. Observations and Findinas
- The inspectors reviewed the licensee's investigation. which revealed i
l that the MAR functional test was originally scheduled to be performed to i
completion by a dedicated crew that had been extensively briefed and !
rehearsed for the task. Delays in the performance of the functional ;
test resulted in the dedicated crew being relieved by a crew that !
received only a face to face turnover on the task. ,
.
The procedure to restore the EDG after the MAR functional test. MAR 96- ;
10-05-01 TP-1. Attachment A. stated that after the diesel engine had !
been stopped for at least 15 minutes. but not more than 20 minutes. '
steps 4.6.30 through 4.6.34 should be performed. These steps are !
intended to roll the diesel slowly to vent moisture and oil out of the
~
"
cylinders. Step 4.6.30 trips the fuel racks. which should prevent an
inadvertent diesel start while rolling it with air. The licensee
reviewed the procedure for adequacy and concluded that the functional ;
!
i
t
_ _ _ _, _, _ .
6
test procedure'was adequate and in sufficient detail to perform the task
without failure.
After the diesel had been stopped,' but prior to com]leting the steps.to
roll the diesel, the control room operator called t1e plant operator and
directed him to perform a different task. The plant operator inquired
as to the im)ortance of the function, but did not inform the control ,
room as to t1e status of the MAR functional' test restoration procedure. !
When the plant o)erator returned to the MAR functional test procedure,
over 19 minutes lad elapsed since the diesel had been stopped. The !
operator proceeded to roll the diesel over, but did not complete all ;
required steps in the procedure, including 4.6.30, which would have l
prevented an inadvertent diesel start.
4
Technical Specification (TS) 5;6.1.1 requires, in part, that procedures i
be implemented covering activities as recommended in Regulatory Guide l
1.33, Appendix A. Revision 2. dated February 1978. A)pendix A !
recommends administrative procedures to cover the aut1orities and
responsibilities for safe operation and shutdown, procedure adherence
and temporary change method. The licensee implemented the above
Appendix A recommendations, in part, through Procedure Al-500, Conduct
of Operations and 01-09, Operations Procedures. 01-09 requires that
activities will be performed in accordance with approved instructions.
The operator's failure to' comply with the instructions in MAR 96-10-05-
01 TP-1. Attachment A is a violation. VIO 50-302/97-01-02. Failure to
Follow Procedures, Resulting in an Inadvertent Emergency Diesel
Generator Start. !
c. Conclusions
The failure of a non-licensed operator to follow the MAR functional test
procedure resulted in an inadvertent emergency diesel generator start.
Contributors to this event, such as poor briefing and preparation of the
operator, assigning the operator to extraneous tasks during the
performance of a time sensitive evolution, and the operator failing to
perform vital steps of the procedure are indicative of performance
problems which still exist in plant operations.
04 Operator Knowledge and Performance i
04.1 00erator Awareness and Ouestionino Attitude
a. Insoection Scone (71707)
The inspectors continue to monitor operator performance in response to
previously documented deficiencies. .
1
b. Observations and Findinas
The inspectors have observed numerous examples of operator performance
that were indicative of the status of the licensee's safety culture. l
The licensee has made it a priority to improve this aspect by supporting !
!
!
7
and encouraging questioning attitudes and open decision making. Some
examples of questioning attitude and conservative decision making
included: the control room refusal to authorize inappropriate scheduled
Mode 5 work, questioning of the IB DH pump oil usage trend prior to a
train A outage that resulted in delaying the outage for a week to
resolve, questioning of DH system venting problems, drain valve work
that was conservatively stopped without the normal makeup path in
service, and engineered safeguards cabinet work that was sto] ped due to
a fuse concern. The fuse concern turned out to be not a pro)lem but
operators conservatively delayed work for a day to ensure their concern
was resolved. Another example of questioning attitude was the work of
engineering to troubleshoot and discover 3roblems with chlorine monitor l
testing. These items are discussed elsew1ere in this report.
Some examples of poor conservatism and questioning attitude were also
observed. They include the scheduling of the inappropriate Mode 5 work
caught by the operators, the initial change by the operations shift of i
fire protection system recirculation flow on verbal and incomplete l
guidance late reports required by 10 CFk 50.72 (addressed in IR 50- 1
302/97-04), a poor briefing and preparation of an EDG operator for an l
evolution, and assigning the EDG operator to extraneous tasks during the
performance of a time sensitive evolution which contributed to an
inadvertent EDG start due to a missed procedural step. ;
c. Conclusions
The licensee staff exhibited an adequate level of conservative decision
making and questioning attitude. Several good examples were observed
but some poor examples continue to be found. Lict see management
continues to emphasize development of a conservat W safety culture.
06 Operations Organization and Administration
06.1 Effective February 18, 1997. Mr. J. Cowan assumed the duties of Vice
President. Nuclear Production, from Mr. P. Beard. Senior Vice President.
Nuclear Operations. The following Directors and their departments now
report to Mr. Cowan:
. Mr. B. Hickle. Director. Nuclear Plant Operations
. Mr. R. Widell. Director. Training
. Mr. W. Conklin. Director Materials and Controls
. Mr. D. Kunsemiller. Director, Site Support
The following executives now report to the Senior Vice President.
Nuclear Operations (Mr. R. Anderson, effective March 3. 1997):
. Mr. J. Holden. Director. Nuclear Engineering and Projects
. Mr. J. Baumstark. Director. Quality Programs
. Mr. J. Cowan. Vice President. Nuclea- Production
- - . - - - - . .- . . . - -
I-
8
07- . Quality Assurance in Operations
07.1 Licensee Self-Assessment Activities
a. Insoection Scooe (71707. 40500)
The inspectors' reviewed various self-assessment activities which
included:
. _ Routine reviews of Nuclear Quality Assessments (NOA) activities;
e Observation of an exit interview for a N0A monthly audit.
- Observation of several Plant Review Committee (PRC) meetings and
review of PRC Meeting minutes:
e Observation of the licensee's internal Restart Readiness Review
Panel meetings:
- Observations of subcommittee and full Nuclear General Review
Committee (NGRC) meetings on January 14 and 15.
b. Observations and Findinas
N0A reports appeared thorough and diverse. The inspectors noted several
examples of timely and responsive NOA surveillances in potential problem
areas. N0A Audit 97-01 had several good findings in the Engineering
area. but the inspector observed that an Engineering representative did
not attend the audit exit meeting The licensee recognized the negative
impact this had on resolution of the findings and took appropriate
corrective action to ensure it would not recur. The inspector reviewed
N0A staffing plans and observed that the licensee had established a two
year rotation plan for four N0A auditor positions, staggered at six
month intervals, and was attempting to target rotation candidates for
inclusion into N0A versus accepting other de)artments' excess personnel.
The inspector concluded this would enhance tie effectiveness of NOA.
The inspector also observed that all N0A findings are entered into the
licensee's corrective action program via generation of a Precursor Card
(PC) and that the NOA auditor determined the grading of the resultant
PC. Changes to the grade and consecuently to the -level of investigation
the PC received had to be concurrec on by NOA. The ins)ector concluded
this was a beneficial practice that enhanced N0A owners 11p of issues.
The PRC provided a thorough review of issues. A good, detailed
discussion and rejection of an issue was noted regarding the
implementation of modification on reactor building
chambers to address Generic Letter 96-06 concerrs. Although
penetration
theexpansion
inspector observed an omitted independent verification requirement, as
. discussed in )aragraph 01.4. PRC discussion of the DH system venting
concern was tlorough. conservative, and probing. The committee
carefully reviewed an associated 10 CFR 50.59 evaluation and challenged
several~ decision points taken by the author. The chain of custody
- - . - - - .- - - - . . . - - . _ _ - - . - - . - - -
,
l I
,
!
i
9
4 l
>
forms, implemented to address previous problems regarding implementation
of PRC ex)ectations that formed the basis for approving items- appeared
.
. to be worcing successfully. The inspector verified several examples .
Where the completion of an item was delayed until.the PRC custody form !
was completed. At the end of the inspection period, the licensee was in !
the process of evaluating several restrictions to the use of alternate i
PRC members and establishing a full time PRC director to increase
'
1
. consistency and oversight. The inspector concluded the licensee's i
! planned changes would increase the effectiveness and value added of the :
.
PRC. which has already exhibited improvement from previous PRC
!
performance in the areas of questioning attitude and willingness to set
.: a high standard and to reject items that do not meet that. standard. PRC
meeting minutes were noted to be thorough and accurate representations
of the items presented. ;
i The NGRC conducted an extensive review of site activities. The l
inspector observed that numerous, new offsite and onsite members have i
been incorporated and that member ex3ectations were promulgated by the i
new chairman in an effort to raise t1e standard of expectations for NGRC l
l conduct and questioning attitude. One offsite member was absent for j
'
personal reasons but did ensure his input was considered by faxing in i
comments and questions. The absent member's subcommittee, the Quality I
and Regulatory Verification Subcommittee, had all new internal members
and was hampered by the absence of the chairman and the lack of guidance ,
and expectations as to the final desired product the subcommittee was to
produce. The inspector concluded all subcommittee members needed to !
review their charter. The inspector also observed that several offsite i
members departed prior to the conclusion of the NGRC agenda due to it !
being longer than in the past. The inspector discussed these '
observations with the NGRC Chairman who is taking corrective action.
The inspector concluded that the NGRC exhibited an atmosphere sup)orting
rigorous questioning and open discussion that was suoportive of t1eir
role as site management oversight.
c. Conclusions
The inspectors concluded the licensee was actively restructuring their
self-assessment activities in an attempt to improve their programs.
Although some problems were observed. they were primarily change related
and due to people gaining familiarity with a new process or a new
program.
07'.2 Imolementation of New Corrective Action Proaram i
a. Insoection Stone (71707. 40500) !
The inspectors have continually monitored the new corrective action
process the licensee implemented in November of 1996 by the following: ,
- -Reviews of most precursor cards entered in to the system: ;
- Observation of a management CAR 6 meeting:
--- -. . - . . . . -
i
10
. Observations of corrective action Precursor Card Screening
Committee meetings.
b. Observations and Findinas
The inspectors observed that the licensee's program as defined by CP-
111. Processing of Precursor Cards for Corrective Action program.
Revision 55. still contained numerous deficiencies and poorly defined
expectations. However, the licensee's new corrective program manager,
who assumed his position in January 1997. has recognized several of the
same problems in parallel and was actively developing changes to the
process. Examples of the problems observed by the inspectors and the
licensee included:
e initial event corrective action not covered under the scope of the
precursor card:
- no specific requirement to veri #y extent of condition for a
problem adverse to quality:
. the role of the CARB is not well defined:
e lack of specific standard formats:
i
e granting of extensions controlled by root cause leaders doing the
work; and
e poor management visibility and knowledge of timeliness and root
cause investigation status:
The inspectors also observed that the arogram was burdensome to
administer due to the large number of 3Cs. Approximately one thousand
Pcs were initiated in January 1997, which indicated the process had an
appropriately low threshold, although thoroughly dispositioning this
many problems remained a challenge to the licensee.
c. Conclusions
The inspectors concluded the corrective action program was functioning
adequately, but several deficiencies detracted from its effectiveness.
The licensee was actively working to improve the process and correct
these deficiencies.
07.3 Manaaement Assessment in Plant Doerations
a, inspection Scone (40500)
The inspectors reviewed the first month's results of the licensee's
initiative to monitor supervisory effectiveness in the area of
operations.
11
b. Observations and Findinas
The licensee has begun an initiative to evaluate management oversight
effectiveness in the area of operations. The performance indicators
chosen included the following:
o tracking the amount of time assessing operations by not only the
operations de)artment, but by maintenance, engineering, plant
management. slift managers, and senior managers;
e tracking the amount of crew observations by shift supervisory
personnel:
e a composite ranking of crew performance: (This was done by
assessing the results of all observations oy all departments); and
e assessing the operators in: knowledge, procedure use, questioning
attitude, communications, self-checking, briefings, teamwork, and
safety.
The inspectors reviewed the results of the first month of assessment.
It was noted that this program was new and disparities existed in
performance assessments for the same crews between the various groups.
The licensee has also identified this and was working to develop better l
criteria. It was also noted that some groups and shift supervisors were
not meeting expectations for performing observations.
c. Conclusions
The inspectors realized that since this was a new program and that with
just the single data point, no conclusions could be reached. The
inspectors will continue to follow the implementation of the program to
assess its effectiveness.
08 Miscellaneous Operations Issues (92901)
08.1 (Closed) VIO 50-302/96-05-01: Failure to Follow Procedures to Initiate
Corrective Action for Bent Main Steam Line Hanaers.
(Closed) URI 50-302/96-05-02: Desian Concerns with the Main Steam Lime
Hanaers Used in Seismic and Other Dynamic Load ADDlications
Details of these problems were previously documented in Inspection
Report (IR) 50-302/96-05. The technical adequacy of the licensee's
response to these problems was reviewed and accepted by the NRC staff as
documented in a letter to Florida Power Corporation (FPC) dated
January 22, 1997. The inspectors verified that the licensee had
appro)riately initiated corrective actions for subsequent suspected
opera)ility problems. Consequently, this item is closed.
,
,.
i
!
!
L
12 l
-:
'
JL Maintenance l
'
1
M1 Conduct of Maintenance
M1.1 Soent Fuel Pool Level Transmitters
!
a. -!
Insoection Scoce (61726._ G707)
.
~ Evaluate that maintenance and surveillances of the Spent Fuel Pool Level !
Transmitters are conducted in accordance with TS 3.7.13 !
!
.
b. Observations and Findinas
On October 31, 1996, it was recognized by the licensee that the i
instruments normally used to perform Technical Specification (TS) i
surveillance requirement (SR) 3.7.13.1 were out of calibration. Work l
Request (WR) NU 0338665 was written on that day to fabricate a measuring +
stick, which could be used to measure spent fuel pool level. ;
TS 3,7.13 requires that during irradiated fuel movement. at least once :
per seven days, the spent fuel pool level be verified to be greater than ,
156 feet above plant datum. Level Transmitters SF-1-LT1 and SF-1-LT2 -
feed indicators in the main control room which are normally used for the -
TS surveillance.
Instrumentation and Control (I&C) shop technicians attempted to
calibrate SF-1-LT1, but were unable to calibrate the instrument within ,
the required .5% tolerance. The licensee issued Precursor Card (PC) 96- t
5697 on December 16. 1996, to document that both instruments were out of '
calibration and that SF-1-LT1 could not be calibrated within tolerance. !
The licensee' completed an apparent cause determination on January 15, ,
1997. As part of the apparent cause determination, the licensee !
evaluated the issue and concluded that no TS violations had occurred.
This was based on the premise that since the surveillance procedure
acceptance criteria were conservative compared to the TS requirements. :
any drift of the instrument would be accounted for. TM s position was
challenged by the inspectors. Surveillances must be congleted with -
calibrated instrumentation to be valid. !
l
As part of the apparent cause determination the licensee reviewed the ;
calibration history of these instruments. It was identified that the
last time SF-1-LT2 was calibrated was February 28, 1992, and the last ,
time SF-1-LT1 was calibrated was in November 10, 1987. The licensee's :
calibration program required these instruments to be calibrated once I
every two years.
The inspector reviewed the last com)leted data sheets for both !
instruments. While a complete cali) ration was com)leted on SF-1-LT2, ;
only a single point calibration was completed on S -1-LT1 which simply :
compared the transmitter to the level indicatcr reading. This was j
!
. i
...
.!
13
'
performed on November 10, 1987.'but the review and approval was not
completed until February 1, 1988.
The inspector's review located'a completed Problem Re) ort (PR) 90-8002.
which was written on November 21, 1990, to identify tlat SF '.-LT1 and
SF-1-LT2 were out of calibration. At that time, operations was notified
that the instruments were inoperable and could not be used for the
surveillance. The PR also had a corrective action to periodically
notify the operations department that the instruments were inoperable
until the problem was corrected. Under the corrective actions for this
PR. WR 271688 was completed for SF-1-LT2 on December 14. 1990. However,
a note was attached to the PR which stated that WR 27.1687 written for
SF-1-LP . rould not be completed as the instrument would not calibrate
within t d Dances. As a result of the inability to calibrate the
instrurr,ent. Re
on February 4.1991.questThefor
PREngineering
was closed onAssistance
February 11.(REA)
1991,91-114
with a was written
statement that all corrective actions were completed. SF-1-LT1 was not
in calibration at that time, but an engineering-hold was placed on the
calibration of the instruments pending the completion of the REA
actions.
The REA stated that the instrument could not be calibrated and that
parts were becoming hard to obtain. Original plans under the REA were
to replace the existing displacer system with ultrasonic level 3
indicators. However, when problems were encountered with ultrasonic :
level indicators installed on a different system the proposed )
modification was cancelled. No other corrective actions were taken. j
5 1
~
During the period while SF-1-LT1 was out of calibration, there were ten I
Jeriods during which irradiated fuel was moved. During the period while
,'
)oth of the instruments were out of calibration, there were five periods
when irradiated fuel was moved. Technical Specification Surveillance
'
Requirement 3.7.13.1 requires that the licensee verify the fuel storage
pool water level is 2156 foot above plant datum once per 7 days during
- movement of irradiated fuel assemblies in the fuel storage pool. The
s failure to perform a valid surveillance is a violation. VIO 50-302/97-
- 01-04. Failure to Perform Technical Specification Surveillance for Spent
Fuel Pool Level.
Following identification of weaknesses by the licensee and ths 1
inspectors in the original apparent cause determination. the licensee
upgraded the PC to a level B. which requires a formal root cause
evaluation.
4
While 3erforming the root cause evaluation, one of the causes identified
was a areak down in the preventative maintenance (PM) process which
calibrated in-field instruments. It was identified that if the PM had
been deferred. it often was not rescheduled. The licensee identified
approximately 150 instruments that were out of calibration and an
additional 720 instruments that were past the nominal calibration date,
but still within the allowed 25 percent grace period.
- .
l
14
The licensee evaluated the out of calibration instruments and identified
several instances where the instruments were used in safety related
applications for operating data or surveillances. Four Pcs were issued
to address these issues. EDG-1B was declared ccnditionally operable and
potentially inoperable based on out of calibration jacket coolant water
temperature instruments. The licensee veri fied that redundant
calibrated instruments were available on the aiesel generator. The
licensee is taking corrective actions to address these identified
deficiencies. Programmatic weaknesses which contributed to the
violation are being assessed by the licensee.
c. Conclusions
Several personnel errors and programmatic instrument calibration
problems were identified as a Violation (VIO 50-302/97-01-04) of
technical specification surveillance requirement 3.7.13.1 for Spent Fuel
Pool Level verifications.
M1.2 Work Controls on the Plant ComDuter
a. Insoection Scone (62707)
The inspectors reviewed an initiative by the licensee to evaluate and
improve work controls on the plant computers.
b. Observation and Findinas
In response to concerns identified by the Director. Nuclear Plant
Operations (DNP0), a surveillance was performed by the Quality Programs
department.on work controls on the plant computers. These computers are
used in the main control room for various parameter monitoring and alarm
functions.
The surveillance. OPS-97-0003 was completed on January 10, 1997, and
presented to the DNPO in the daily staff meeting. The surveillance
identified several areas where weaknesses were evident and improvements
were recommended. These identified weaknesses were as follows.
e A PM/ surveillance program had not been established to ensure
reliabilit, of the plant computer. Maintenance had only been
performed on the computer when the system failed,
o The entry conditions for licensee procedure AP-430. Loss of
Control Room Alarms were nonconservative. Partial plant computer
loss may be sustained, rendering critical plant parameters
unavailable, but a partial loss was not explicitly addressed in
the procedare.
- Work activities being performed to troubleshoot and repair the
plant computer taking place under WR NU 339899, were outside the
scope of the WR 15
e Poor work practices were evident as a result of an inspection of
the Plant Computer cabinets and component terminations.
The licensee maintenance and system engineering management agreed that
any work performed on the plant computer, other than rebooting, and be
done under a WR, with I&C sup) ort. This agreement was documented by an
internal memorandum from the ianager. Nuclear Plant Technical Support to
the DNP0.
To date corrective actions to address the other identified weaknesses
have not been performed. An initial assessment of AP-430 by operations
was that no weakness existed, but this was rejected by the Quality
Programs department and returned to operations for further review.
c. ponclusions
The decision to assess the maintenance controls of the plant computer
was a proactive initiative on the part of the licensee management. The
assessment resulted in more stringent controls being implemented.
M1.3 Maintenance Observations
a. Insoection Scope (62707. 92902. 62703)
The inspectors observed maintenance activities during the EDG-1A system
outage. Adherence to work instructions, resolution. of identified
problems, proper maintenance practices and documentation were assessed.
b. Observations and Findinas
WR NU 0339596 was written by the licensee to perform an upgrade to EDG-
1A to allow a larger continuous run rating. New turbochargers and dual- )
'
pass combustion air intercoolers were installed in accordance with MAR
96-10-05-01. During the various period.s that the inspectors witnessed
the work, good Foreign Material Exclusion (FME) controls and work
control practices were observed. Continual presence by engineering,
both systems and design, and maintenance management was observed. The
work practices observed in the field revealed no problems.
Problems were encountered with other aspects of the task, however. The
original scope of the diesel outage was scheduled for approximately one
week. Delays and other problems resulted in the outage taking
approximately two weeks to complete. '
On January 22. 1997, the mechanical maintenance technicians working on
the diesel witnessed electrical arcing which was reported to management.
WR NU 340315 was issued to trouble shoot and repair the observed
problems. The inspectors reviewed the electrical maintenance and I&C
logs and found that on three occasions technicians were dispatched who
were unable to locate the arcing. These delays resulted in delays to
restart of the diesel following completion of maintenance and
modi fications. The I&C technician did not consult with the mechanical
.
_
16
,
maintenance technician, concerning the exact location of the arcing,
until the outage schedule had been impacted. Quality Programs, as part
of Audit 97-01, issued PC 97-806 on January 30, 1997, stating that the
functional test of MAR 96-10-05-01 was delayed as a result of
management's failure to recognize the impact that performing the WR
would have on the test.
The trouble shooting finally identified, on January 30, 1997, that
insulation on a wire feeding speed switch EG-19-SS had been broken,
causing an intermittent short. While identifying this problem, a
-
different wire was identified that had been pinched that had to be
replaced. According to drawings the wire was # 12 AWG, but the
'
technicians identified the wire in the field to be # 14 AWG. Delays
were caused while engineering researched and found that the correct wire
was # 14 AWG. Revisions to the drawing were submitted.
.
Other problems were encountered during the performance of the
maintenance and modifications. Jacket coolant was refilled using one
section of the operations procedure before it was realized that a new
section existed for filling the system with corrosion and biological
inhibitors.
A leaking instrument tube line was identified on February 1.1997,
during post installation testing of the MAR. The leak appeared to be
colored water, which indicated that it was jacket coolant water. The
leak was not isolable and necessitated repairs prior to restoring the
diesel to functional status.
,
On February 1,1997, after repairs were completed to the leaking
instrument tubing. the EDG was run for the MAR functional test and post
maintenance testing. The following day, on February 2,1997 it was
identified that several post maintenance test (PMT) packages on EDG-1A
had been omitted during the diesel run of the previous day. Pcs97-723,
97-757, and '97-755 were written to document several missed PMTs on the
EDG-1A.
On February 3. 1997. PC 97-895 was written to document missed PMTs on
maintenance on RWP-2A and RWV-38. The licensee's apparent cause
evaluation on all of these missed PMTs revealed that they had all been
scheduled to be completed on January 31. 1997. When work delays
prevented the completion of the PMTs on that day. no mechanism existed
to maintain the tasks on the schedule or to place the tasks on the
following week's schedule. All of the PMTs were rescheduled and were
successfully completed. The lack of a mechanism to recognize
uncompleted tasks and maintain them on the schedule was identified as a
weakness.
On February 5. 1997., the inspectors attended a post job critique for the
EDG-1A maintenance and modifications. It was identified at this meeting
that there was no assigned person responsible to coordinate all of the
various tasks. Factors contributing to the problems encountered
included the weakness discussed above in the scheduling process, too few
-
<
_ _ -
17
people prepared and briefed for the tasks to relieve personnel dedicated
to aerforming the tasks, and a lack of a coordinated review of work
paccages prior to issuance. The lack of a responsible individual to
coordinate the task has been o recurring issue at the site.
,
c. Conclusions
Problems were encountered throughout the performance of the EDG-1A
outage. Lack of coordination was identified as a key contributor. A >
weakness was identified for the absence of a mechanism to ensure that
tasks scheduled for the weekend that were not completed were rescheduled
for the subsequent week.
M1.4 Imoroner Documentation of Test Instrument Connections
a. Insoection Scoce (62707)
As part of the installation of MAR 96-10-05-01 on EDG-1A. a Dranetz data
- accuisition system was installed to perform post modification testing
4
anc future testing. During review of the post installation work
package, the licensee discovered that the documentation for the
installation had not been completed by the relay technician. !
b. Observations and Findinas
PC 97-738 was written on February 3,19?;7. to identify this failure to
document the completion of the work. The apparent cause determination J
that the licensee made determined that poor communications between the )
project manager and the relay technician had not clearly identified the -
need to complete the documentation.
The inspectors interviewed the project manager and reviewed the
installed system data from the previous diesel test runs. The data were
within the expected range. Discussions with the licensee revealed that,
if the system had been connected incorrectly, no data would have been
received. The relay technicians routinely installed this equi) ment at
both the nuclear site and at the fossil units. According to t1e
licensee, this was normally considered within the skill-of-the-craft for
relay technicians. The instructions were developed for electrical l
maintenance and I&C technicians, who do not normally install these
instruments, by the technician who performed the installation.
1
c. Conclusions l
As a result of the incomplete documentation for a MAR package .
completion, the need for better communications has been identified by
the licensee. The test instrument has been verified to have been "
properly installed. No further actions are required.
i
h
18
,
M1.5 Testina of Toxic Gas Chlorine Monitors
a. Insoection Scope (61726. 37551)
The licensee has proactively been performing testing on a station
constructed to re)roduce the installed toxic gas chlorine monitor. This
initiative was tacen in an effort to increase reliability of the
installed system. The inspectors have been monitoring these tests,
witnessing the efforts of the engineering staff conducting the tests.
b. Qbg_r.y_qt
b r Ions and Findinas
Testing revealed a lack of repeatability for time response testing of
the system. The acceptance criteria was 15 seconds from receipt of the
chlorine at the remote sensor until completion of the control room
emergency ventilation system switching to recirculation mode. Normally,
per PT-366. Toxic Gas Detection System Calibration (Train A) and PT-367.
Toxic Gas Detection System Calibration (Train B). time response testing
is performed immediately following span testing, which supplies chlorine
test gas to the sensor. On February 10. 1997, the licensee performed
the span test but elected to wait until the next day to perform the
response time test and to evaluate the effect of not having put chlorine
gas previously on the sensor. This was the condition that would exist
on a valid chlorine gas actuation. Without the span test being
performed immediately prior to performing the response time test. the
response time test failed.
Further tests revealed that when the sensor was exposed to chlorine
prior to the response time test, the response times were reduced. PC
97-978 was written on February 12, 1997, to document that the toxic gas
chlorine monitors may need to be exposed to chlorine for an unknown
period of time before they can respond fast enough to pass the 15 second
acceptance criteria. By performing the span test 3rior to the response
time test. the system was preconditioned to pass t1e response time test.
As a result, the licensee declared both trains of chlorine monitors
inoperable and placed the control room emergency ventilation system in
the recirculation mode. The licensee was evaluating installed designs
at other licensee's facilities in an attempt to identify a reliable
design. The licensee indicated a plan to install a reliable system
prior to restart from the current outage.
Te-Snical Specification 5.6.1.1 requires, in part, that procedures be
developed and implemented covering activities as recommended in
Regulatory Guide 1.33 Appendix A. Revision 2 of February 1978. Among
these are surveillance procedures for each surveillance test listed in
the technical specifications. The design basis, as defined in the Final
Safety Analysis Report (FSAR), Section 9.7.3.1. for the Control Room
Emergency Ventilation System (CREVS). included two trains of toxic gas
chlorine monitors which were to be operable at all times. This was to
allow the system to maintain control room habitability during a toxic
gas release. Technical Specification Surveillance Requirement 3.7.12.3
_. . _
19
required that the licensee verify each CREVS train actuates to the .
emergency recirculation mode on an actual or simulated actuation signal,
at least once per 24 months.
c. Conclusions l
The inadequate procedure, which allowed the preconditioning of the
chlorine sensor, prevented an accurate response time test from being
performed. The licensee took prompt corrective actions by declaring the
toxic gas monitors inoperable and placing the CREVS in the recirculation
mode. The licensee was actively pursuing long term corrective actions <
by working with the sensor manufacturer and consulting engineers. This ,
licensee identified violation meets the requirements outlined in Section
VII of the Enforcement Policy and will not be cited. This issue is
'.
identified as Non-Cited Violation NCV 50-302/97-01-05. Inadequate i
Surveillance Procedure to Test Operability of the Toxic Gas Chlorine !
'
Detectors.
i
M1.6 Schedulino of Work on Non-Nuclear Instrumentation ;
a. .[0.s.pgqtion Scooe (62707)
On February 4.1997, the licensee identified that the weekly work
schedule had clearances being placed on the pressure transmitter
isolation valves for Instruments RC-132-PT and RC-131-PT1.
'
b. Observations and Findinas
Work packages were taken to the main control room for approval to begin
4
work. The operations SSOD identified that neither the work packages (WR
, NU 0337967 for RC-131-PT1 and WR NU 0337968 for RC-132-PT) nor the
schedule provided any indication or recognition that the transmitters ,
provide in)ut signals to the Power Operated Relief Valves (PORVs) and l
'
the Decay deat drop line auto closure initiation. The PORV is required
to be operable in modes 1. 2 and 3. The Auto Close Initiation system is
recuired to be operable in modes 1. 2. 3 and 4. In the present plant
moce. neither system was required to be operable. However, this was not
'
clear on the work request packages, and no evaluation had been completed
for the impact of removing these instruments from service. The SSOD
refused to authorize the work packages until a full evaluation of the
impact of the isolation of the instruments had been completed.
!
c. Conclusions
Scheduling of work packages which do not identify the impact on plant
conditions and provided work packages to the field operators who do not '
recognize the impact of the task is a recurring problem. This is
identified as a weakness in the implementation of the work planning
program.
l
-
20
M1.7 Unolanned Alarm Durina Instrumentation and Controls Work
a. Insoection Scope (62707)
On February 3, 1997, an annunciator alarm was received in the main
control room for feedwater control valve air failure. At the time of
the incident, the unit was in mode 5, and feedwater was not in
operation. The alarm was not expected as the result of any work in
progress. At the time the alarm was received, the inspector was in the
control room and witnessed the licensee's response.
b. Observations and Findinas
Investigation revealed that I&C technicians were performing work on FWV- -
39, which caused the alarms. It was confirmed that the operations work
controls supervisor was aware of the work in progress, but he was not
aware of any ex)ected alarms. The inspector questioned the I&C
technicians. T1ey were not aware that the alarm would result from the
task they were performing and the WR did not indicate that an alarm
would be received.
c. Conclusions
Several events contributed to the operators not being aware that an
alarm might be received. Although the work controls supervisor was
aware of the work in progress, the operations shift was not. The lack
of indication on the work package contributed to the confusion. The
inspectors identified that even though the mechanisms exist to include
warnings about these observed problems in the work packages, the lessons
learned are rarely considered when planning a work package. Instead,
the process relies on the technicians and operations review to identify 1
problems. This lack of thorough evaluation is another example of the !
weakness in the implementation of the work planning program identified i
in paragraph M1.6. 1
M8 Hiscellaneous Maintenance Issues
M8.1 (Ocen) URI 50-302/96-17-03. Failure to Conduct Reauired Technical
Soecification Surveillance Testina on Safety Related Circuitry I
a. Insoection Scoce (37551. 92902)
On January 31. 1997, the licensee identified that test deficiencies
existed in licensee Procedures SP-907A Monthly Functional Test of 4160V
ES Bus "A" Undervoltage and Degraded Grid Relaying and SP-907B, j
Monthly Functional Test of 4160V ES Bus "B" Undervoltage and Degraded
'
Grid Relaying.
,
b. Observations and Findinas
The test deficiency identified that contacts in all three channels of
the first level undervoltage relays (FLUR) and second level undervoltage i
21
relays-(SLUR) were not being tested in accordance with the TS :
requirements. The FLUR and SLUR relay contacts were subsecuently tested .;
satisfactorily in accordance with the TS. This issue is-icentified as. i
an additional example of URI 50-302/96-17-03. Failure to Conduct
Required Technical Specification Surveillance Testing on Safety Related !
Circuitry, pending completion of the licensee's review under Generic !
Letter (GL) 96-01. !
.
c. Conclusions
No further actions are required at this time. URI 50-302/96-17-03'
remains open pending completion of the licensee's GL 96-01 review and l
.the inspectors' assessment of the findings. l
JJL. Enaineering 5
El Conduct of Engineering I
El.1 General Comments (37551) j
The inspectors reviewed various Engineering and support activities which I
included presentations to licensee management on January 31 1997 'and i
February 11. 1997, by the Emergency Diesel Generator (EDG) and Emergency
Feedwater (EFW) Interim Fix Option Team. The team was chartered to
assess the feasibility of starting the plant up with the interim 150 Kw 1
load upgrade but prior to the )lanned long term larger upgrade of the . 1
EDG capacity. The inspector o) served that this was a multi-disciplined
team, which took a conservative and questioning approach to the design
basis challenges that must be resolved before those systems would be
acceptable for restart. The inspector concluded the team was being very
realistic and appropriately involved Framatome vendor support to address
design issues.
The inspectors also reviewed activities associated with resolution of
corroded primary valve seats and difficulties in obtaining an effective
vent of decay heat system piping. Engineering personnel provided good ,
} support for the remainder of the reviewed or witnessed activities.
Activities were found to be adequate, well controlled, and documentation
usually provided sufficient detail and appeared technically adequate.
Additional details regarding notable issues are described below.
E1.2 Non-Safety Related Comoonents in Safety Related Acolications j
I
'
a. Insoection Scone (37551. 92903)
The inspectors reviewed the licensee's investigation and corrective
actions for an issue identified where non-safety related components were
used.in a safety related application.
l
l
. . - . . .
.
.
22
b. Observations and Findinas
During a review of the licensee's 10 CFR 50 Appendix R program, the
licensee identified a need for voltage protection on current
'
transformers (cts) installed on several systems. The decision was made
to review MAR 77-07-01-14, which was installed in 1985 as a part of the
Ap)endix R upgrade. The secondary protection installed as part of this
' MAR 3rotected the Cts which provided remote indication of amps. vars.
'
and (ilowatts for the EDGs in the main control room. During the review.
. the engineer identified that these protectica devices were neither
seismically qualified nor procured as safety related.
PC 97-0050 was issued on January 9.1997, to document this finding. At
that time, the EDGs were evaluated to be conditionally operable /
potentially inoperable, pending the final review of the impact of the
non-safety related devices being installed. This was based on the
assumption that in mode 5. loading would be greatly reduced and load
management (which requires the kilowatt indication) would not be
necessary.
On January 21, 1997, it was identified that although the load demands in
mode 5 would be low, the controlling procedure for a load management ;
during a loss of offsite power (LOOP) event would be AP-770. Emergency i
<
Diesel Generator Actuation. This procedure did not address the reduced i
load demands and could lead to overloading the diesel generators, if no
kilowatt indication was available. The shift supervisor declared both
diesel generators inoperable and entered TS action statement 3.8.3.
EDG-1A was already inoperable for preplanned maintenance and
modifications.
4
The licensee continued evaluating the devices while the Operability
Concerns Resolution (OCR) was completed. A spare protector was
disassembled and inspected. The device is a thyrite type of device
which prevents voltage surges which could damage circuitry. The device
was also supplied to an independent contractor for evaluation.
The contractor concluded that the device would perform its intended
function both during and following a seismic event. The licensee issued
the completed OCR on January 26, 1997, and concluded that the diesels
were operable, but degraded. EDG-1B was declared operable. but EDG-1A
remained inoperable pending completion of the ongoing diesel outage.
r
The licensee is currently evaluating replacement protectors and the
necessary requirements to upgrade the existing protectors to safety
related.
In a second example during preparation to replace MUV-103, the
Engineered Safeguards (ES) isolation valve between the makeup system and
the Reactor Coolant Bleed Tanks (RCBT). the boric acid storage tanks
(BAST). and the demineralized water supply, the licensee discovered that
the installed operator and controller for this safety related valve were
non-safety related. In the licensee's accident analysis, this valve was
.
23
assumed to isolate for a moderator dilution event. With the non-safety
related components installed, this valve cannot be assured to operate
when required. The licensee plans to replace this valve prior to
restoring the makeup system and has added it to their restart restraint
list.
c. Conclusions
The inspectors concluded that these problems were further examples of
inadequate design control. The licensee has taken the necessary
immediate corrective actions and has added final resolution of these
issues to the restart restraint list. This licensee identified
violation meets the requirements outlined in Section VII.B. of the
Enforcement Policy and will not be cited. This issue is identified as i
Non-Cited Violation NCV 50-302/97-01-10. Inadequate Design Control. Non-
Safety Related Components in Safety Related Applications - Two Examples: .
Thyrite Surge Protection Device. Operator and Controller for MUV-103.
El.3 HPI System Modifications to Imorove SBLOCA Marains
a. Insoection Scoce (37550)
In a letter to the NRC dated October 28, 1996, the licensee described
eight design issues that would be addressed prior to restarting the
plant. Design Issue 2. high pressure injection (HPI) system
modifications to improve small break loss of coolant accident (SBLOCA) I
margins, described improving design margins in the HPI system by adding l
flow limiting venturies and crossover piping. However, the licensee
stated that these modifications would not be made prior to restart
because the HPI system currently met its design and licensing basis.
During this inspection the inspector reviewed some aspects of the HPI l
'
system to verify that it did currently meet its design and licensing
basis.
b. Observations and Findinas
l
(1) Peak Claddina Temoerature Exceedina 2300 Dearees F
The inspector reviewed the Final Safety Analysis Report (FSAR).
)aragraph 6.1.1. Emergency Core Cooling System (ECCS) Design
3ases, and noted the following statements:
" Assuming the loss of one core flood tank (CFT) and using
the ground rules specified in Part 4 of Appendix A of the
Interim Acceptance Criteria (where the CFT water is assumed
to be lost after the end of blowdown), the 8.55 square foot
cold leg split results in a cladding temperature rise
exceeding 2300 degrees F because of the long adiabatic
heatup period. The above case assumes the loss of one CFT
coincident with the failure of a diesel. This amounts to a
simultaneous active and passive failure. If only the
passive failure was considered, that is, credit was taken ;
. . _ _ _ . . . _ . _ _ _ _ _ ._ _ _ _ _ . _ _ _ _ _ _ .
!
- l
l
.
- 24
-for both' low pressure injection (LPI) and high pressure [
injection (HPI) pumps, the cladding temperature could be~ !
held below 2140 degrees F if expected rather than design i
peaks are employed." --;
,
- The inspector's concern with these statements was that they were [
'
not-consistent with the current design requirements. 10 CFR [
.
50.46. Acce)tance Criteria for Emergency Core Cooling Systems l
-(ECCS) for _ight Water Nuclear Power Reactors, requires that the 1
peak. cladding temperature (PCT) shall not exceed 2200 degrees F >
'
for all design basis events. Also. 10 CFR 50, Appendix A. General i
Design Criteria for Nuclear Power Plants, requires that plants be
!s designed against an initiating event (i.e., a break in a core i
flood tank line) concurrent with a single failure (i.e., failure :
- of a diesel generator). However, the aoove FSAR statements
indicated that, for.such a design basis event, the PCT could l
l
exceed 2300 degrees F. -l .
'
The inspector informed the licensee of this concern, and i
'
subsequent licensee and ins)ector review of design and licensing i
.information revealed that t1e FSAR statements were incorrect.
4
Supplement No. 4 to the Safety Evaluation Report by the Office of i
Nuclear Reactor Regulation, dated January 28, 1977, stated that !
Babcock and Wilcox had provided revised ECCS 3erformance :
calculations for the worct case break using tie revised evaluation
model which demonstrated that the PCT and the percent of local and
,
core-wide metal-water reaction remained below the limits specified
. in 10 CFR 50 46.~ Supplement 4 further concluded that the analysis i
of the ECCS performance conformed to the acceptance criteria in 10 l
CFR 50.46. The inspector verified that the Babcock and Wilcox
'
i revised ECCS performance calculations (BAW-10103. Rev. 3. Topical
'
Report of 1977) did conclude that the worst case LOCA was an 8.55
square foot cold leg split, which resulted in a PCT of less that
c 2200 degrees F. Further. BAW-10103 calculations did include
,
failure of a diesel generator concurrent with the LOCA.
i Based on the results of this review, the licensee initiated a
, change to correct the FSAR. The inspector verified that the
- incorrect statements had been in the FSAR since 1973, prior to
plant licensing. The inspector also verified that the licensee
initiated PC 97-0784 on January 30, 1997, to address the error in
the FSAR. Since the error was an old design issue in the original
, FSAR that was reviewed by the NRC prior to licensing of the plant.
< and the licensee promatly initiated corrective actions. the
,
inspector concluded tlat enforcement action for this FSAR error
i
was not warranted.
,
4
1
!
_ _ - _
l
_ . _ _
25
':
(2) Reauired 00erator Actions for SBLOCA Mitiaation
(a) FSAR Revision 23 Increased the Number of Reauired Operator !
Actions i
The inspector reviewed FSAR paragraph 6.1.3.1.1,. Design
Evaluation of the HPI System for RCS Cold Leg Small Break '
LOCA: FSAR paragraph 6.1.3.1.2. HPI Line Break Small Break
LOCA: and FSAR paragraph 14.2.2.5.7 Small Break LOCA: and
noted that changes recently made. in Rev. 23. included:
Rev. 23 added two required operator actions to mitigate a
SBLOCA event concurrent with the failure of an EDG. It
described the following required operator actions:
(1) Within 10 minutes after event initiation. the operator
must' select an alternate power supply and open two >
injection valves. This operator action was in the i
previous FSAR revision.
3
(ii) Within 20 minutes after event initiation. the operator l
must isolate normal makeup flow and also isolate RCP ;
seal injection flow. These two operator actions were I
not in the previous FSAR revision, j
l
Rev. 23 added a required operator action to isolate an HPI l
injection line that was broken (with flow substantially l
higher than the other injection lines). The previous FSAR l
revision included a required operator action to balance i
flows in the HPI injection lines - that operator action was
replaced by the new required action of isolating an
injection line that was broken.
Also, Rev. 23 added a required o)erator action in the event
of a LOCA in the letdown line, w1en the operator would be !
required to isolate letdown flow. This operator action was
not in the previous FSAR revision.
FSAR Rev. 23 also stated that HPI flow to the core during
the first 10 minutes after event initiation (with concurrent
failure of an EDG) would be only 36% of the total HPI flow. .
After the operator opened the two remaining injection l
valves. HPI flow to the core would increase to a greater j'
percentage of total HPI flow. The previous FSAR revision
stated that HPI flow to the reactor must be the ecuivalent
of 70% of the flow of one HPI pump, and that woulc be
achieved by four injection lines with one HPI pump.
The inspector concluded that FSAR Rev. 23 increased the
number of required operator actions for SBLOCA mitigation
(from two to five). Also, Rev. 23 described a reduced
__ __ __ _ . ._____ __ . . _ _ _ .- _ _ .. _
..y
-i
1
!
26 .,
amount of HPI flow.to the reactor, higher peak clad ;
-temperatures, and. higher offsite doses. .
(b) HPI Licensino Basis in 1979 Included One Ooerator Action )
The inspector reviewed licensing information, which included'
various letters between the licensee and the NRC leading to ;
an NRC Safety Evaluation. dated May 29, 1979. The Safety !
Evaluation concluded that the licensee's small break LOCA
analysis and ECCS design were in conformance with the l
requirements of 10 CFR 50.46 and noted that the design ;
included an operator action to initiate HPI to two injection :
lines within 10 minutes. In addition, the Safety Evaluation i
stated that the operator action will provide a minimum of j
four injection lines and one HPI pump, which will provide at :
least the 70% of the flow of one pump to the reactor that ;
the licensee determined was needed. The Safety Evaluation i
'
also stated that all three HPI pumps are automatically-
started when the ES signal is actuated. (The licensee's ,
current design included starting only two HPI pumps on an ES
'
signal.) In a )revious licensee letter on ECCS Small Breaks i
Analysis dated rebruary 28, 1979, the licensee stated that !
operator actions to isolate normal makeup or RCP seal i
injection were not needed, because the normal makeup is
isolated automatically on an ES signal and without isolating
RCP seal injection more than 70% of the flow from one HPI l
pump is available as injection into the RCS. In a letter
dated October 9, 1978, the licensee stated that analyses ;
were being performed to determine if operator action was ;
needed to balance the HPI flow in the injection lines and ;
that if balancing was required, then the licensee would !
install flow limiters to preclude the need for such operator l
action. In another letter dated November 7,1978, the
-
licensee stated that the analyses showed that no operator i
action was needed for flow balancing in the HPI injection l
'
lines. In summary, the NRC had licensed the licensee's ECCS
system design with provision for one operator action within !
10 minutes which would ensure at least 70% of the flow of I
one HPI pump to the reactor. l
The inspector concluded that the licensing basis from 1979 ,
included only one required operator action for SBLOCA
mitigation. ,
(c) 'SBLOCA Calculation in 1996 Included Seven 00erator Actions
The inspector reviewed the licensee's current calculation '
for Small Break LOCAs. M96-0032. Reevaluation of HPI
Requirements During Small Break LOCAs, dated May 2,1996.
This calculation was also identified as Framatome i
Technologies Incorporated (FTI) calculation 51-1245866-00. !
The calculation stated that seven operator actions were {
f
!
I
. - . .- --
- -
27
required to mitigate the spectrum of small break LOCAs: 1)
trip all running RCPs within two minutes. 2) initiate HPI
flow through all four injection lines within 10 minutes, 3)
isolate letdown within 10 minutes. 4) isolate RCP seal
injection within 20 minutes, 5) isolate normal makeup within
20 minutes, 6) ensure adecuate HPI flow within 20 minutes,
and 7) ensure adequate EFk flow within 20 minutes. The
calculation also stated that during the performance of the
hydraulic analyses. FTI discovered that the HPI flows
provided by the licensee's system were less than the HPI
flows used in the FTI analysis of record for cold leg pump
discharge breaks. This flow deficit was primarily due to ,
the generic B&W plant modeling assumptions in the FTI
'
analysis of record (i.e., normal makeup and RCP seal
injection automatically isolated on ESAS) and not accounting
for the time delay involved in the licensee's operator
actions to manually isolate normal makeup and RCP seal
injection.
'
The inspector concluded that the SBLOCA calculation of 1996
included seven required operator actions for SBLOCA
mitigation. l
The seven required operator actions in the 1996 calculation were 1
more than the one required operator action in the 1979 licensing !
basis. The seven were also more than the five required operator
actions in the recent FSAR Rev. 23 and more than the two required
operator actions in the previous FSAR revision. The inspector
noted that the increase in required operator actions may represent
a potential increase in the probability of occurrence of a
malfunction of equipment important to safety and therefore, per 10
CFR 50.59, prior NRC review and approval would be requireo.
However, the inspector considered that further review of ti.is
issue was needed to determine if any of the added operator actions
had been reviewed and approved by the NRC between 1979 and 1996.
In addition. inspector review was needed of any procedure, plant
design, or FSAR changes (and related 50.59 safety evaluations)
that added required operator actions or deleted automatic actions.
This issue is identified as the first example of URI 50-302/97-01-
06, HPI System Design, Licensing Basis, and TS Concerns.
1
(3) HPI Desian Not Consistent With Licensino Basis
The inspector noted that Calculation M96-0032 identified a design l
control error with the HPI system. It stated that the licensee's I
licensing submittals on HPI system design and SBLOCA in 1978 and
1979 (and the NRC SER in 1979) incorrectly assumed that normal
makeup and RCP seal injection were automatically isolated at
Crystal River 3. (The 1979 B&W SBLOCA calculation, on which CR3
relied, assumed that normal makeup and RCP seal injection were l
automatically isolated based on a generic B&W plant.) However, l
the CR3 design did not include automatic isolation of normal
l
.
l
l
28
makeup and RCP seal injection. Consequently, the CR3 design would
su) ply less HPI flow to the reactor than assumed in the 1979 B&W
SB_0CA calculation. Calculation M96-0032 stated that isolation of
normal makeup and seal injection was necessary to keep peak clad >
temperatures for a design basis SBLOCA telow 2200 degrees F. The
inspector concluded that the CR3 HPI system was apparently outside
its licensing basis from 1979 through 1997. The inspector also
considered that further review was needed of the consequent impact
on HPI system operability during the period of 1979 throagh 1997
(including what operator actions were included in E0Ps). This
issue is identified as the second example of URI 50-302/97-01-06.
HPI System Design Licensing Basis, and TS Concerns.
(4) HPI Desian Not Consistent With TS
The inspector noted that the CR3 TS included LC0 allowable outage
times for one train of HPI but included no allowable outage time
for both trains of HPI. However, the CR3 HPI system design
included several motor operated valves that were in both trains of
HPI (i.e.: MUV-3 and MUV-9. HPI pump discharge crosstie valves:
MUV-23. MUV-24. MUV-25. and MUV-26. HPI injection valves: and MUV-
27. normal makeup valve). All of these valves had required
surveillances (i.e. , quarterly stroke time tests) and maintenance
(i.e., gearbox & grease inspection). Initial inspector review
indicated that the licensee may have performed some of these j
surveillance or maintenance activities while the HPI system was i
required to be operable. The inspector considered that further (
review was needed to determine when these valves were out of !
service for surveillance testing cr maintenance with the plant in j
Mode 4 or above during the last three years, and in each case how '
TS compliance was affected. This issue is identified as the third i
'
example of URI 50-302/97-01-06. HPI System Design. Licensing
Basis, and TS Concerns.
(5) Licensee Desian Bases and FSAR Reviews Did Not Identify These
.1ssies
As 3 art of the licensee's extent of condition review for design
pro)lems, the licensee was constructing time lines for selected
safety systems. The time lines would, for example, review changes
'
to the systems from the initial licensing basis (i.e.,
modifications, operating procedure changes, licensing basis
changes. FSAR changes. TS changes) to assure that the licensing
and design bases had been maintained.
The inspector reviewed the licensee's time line for the makeup /HPI
system that had been completed on February 10. 1997, and noted
that the time line identified a number of good questions and
potential issues. However, the time line did not identify any of
the issues raised by the inspector in URI 50-302/97-01-06. HPI
System Design. Licensing Basis and TS Concerns.
-. - . _ - -
l
l
l i
1
29 ;
l
The inspector also noted that the licensee's current FSAR review '
project had not identified the above FSAR error (regarding peak !
cladding temperature exceeding 2300 degrees F). The licensee's l
FSAR reviewer stated that the review was focused on verifying that !
FSAR information was implemented in operating, surveillance, and I
maintenance procedures: system DBDs: and TS. However, the review
basically assumed that information in the FSAR was correct. The l
reviewer stated that, therefore, the FSAR review would not have i
been expected to identify such errors in the FSAR. j
i
c. Conclusions i
,
i
'
l An unresolved item was identified regarding the design of the HPI
i system: URI 50-302/97-01-06. HPI System Design, Licensing Basis, and TS j
Concerns. Inspector concerns included the following.
1
-
Since 19'9 6, seven operator actions were identified for SBLOCA
i mitigation: however, the licensing basis since 1979 contained only
one operator action.
- Prior to 1996 the licensee's SBLOCA analysis incorrectly assumed
that RCP seal injection and normal makeup were automatically
isolated.
- The effect on system operability was not assessed with both HPI
trains sharing several active components.
In addition, the inspector noted that the licensee's recently completed j
extent of condition review (time line) for the makeup /HPI system design '
did not identify any of the inspector's concerns.
An error in the FSAR was identified, where the FSAR stated incorrectly )
that for a design basis accident the peak cladding temperature would j
exceed 2300 degrees F (the regulatory limit is 2200 degrees F). In :
addition, the inspector noted that the licensee's current FSAR review l
project had not identified this FSAR error. ,
!
Since this issue was left as an unresolved item with more inspection
needed to reach conclusions. the inspector did not at this time assess ;
the licensee's performance with respect to this issue in the five NRC l
continuing areas of concern. l
1
El.4 10 CFR 50.59 Safety Evaluations
a. Insoection Scone (37550) l
The inspectors reviewed 10 CFR 50.59 safety evaluations for recent
engineering products to assess their adequacy.
,
. _ -~ -.- - . - - - - , - - - - . - - ..- , . - . .. ~
i
L
l
,
,
30
b. Observations and Findinos
.
i The inspectors reviewed 10 CFR 50.59 evaluations for one modification. l
!
MAR 96-10-04-01. Installation of Overpressure Protection for Isolated !
Piping Sections'(GL 96-06). dated January 3. 1997: and for one design
basis document change. EDBD TC No. 536. HPI Flows and BWST Circulation.
' dated January.16'. 1997: and assessed both as adequate, thorough, and :
detailed. The inspectors also reviewed the.10' CFR 50.59 evaluation for !
'
an FSAR change. FSAR Table 6-1 Correction dated January 24, 1997, which
involved core flood tank level and 3ressure; and-noted that it lacked ,
l < sufficient clarity and detail to mace a determination on acce)tability. :
Overall the inspectors noted improvement in the quality of t1e recent i
50.59 safety evaluations reviewed over those of one - two years ago. ,
The inspectors reviewed a 10 CFR 50.59 screening for MAR 94-09-02-01. DC ;
I
Cooling Instrument Enhancements, dated June 27. 1996, which involved
non-safety instrument air to DCV-7. 18, 177, and 178. The inspectors
assessed this 10 CFR 50.59 screening as having a lack of sufficient
detail to support the conclusion that a full 10 CFR 50.59 safety
evaluation was not required.
c. Conclusions
The inspectors reviewed a small sample of 10 CFR 50.59 safety
evaluations for engineering products and noted improvement in the
cuality and thoroughness over those generated one - two years ago.
towever, the sample size was small and therefore, further review will be
needed to verify adequacy of the overall 10 CFR 50.59 program.
The inspector assessed the licensee's performance, with respect to this
issue, in the five NRC continuing areas of concern:
- Management Oversight - Good
. Engineering Effectisteness - Good
. Knowledge of the Design Basis Good
. Compliance with Regulations - Good
. Operator Performance - N/A
E1.5 Decay Heat Valve (DHV) 21 00erability Evaluation
a. Insoection Scone (37551)
The inspectors reviewed the licensee's investigation and disposition of
internal corrosion found on DHV-21. the pump inlet manual isolation
valve for decay heat pump (DHP) 1A.
b. Observations and Findinos
The licensee discovered significant seat leakage while draining DHP-1A
for maintenance on January 20. 1997. Upon disassembly the licensee
observed severe localized corrosion of the seat rings that were
determined to be made of carbon steel. Vendor drawings for the valve
_ _ - _ - - _ _ , _ _
- . _ . _ .. _. _ _ _ - . . _ _ - _ _ . -_ _
i
31-
indicated that the seat rings should be constructed of 316 stainless .
steel, the correct material for this primary system application. The :
licensee appropriately generated precursor card (PC) 97-0472 to
implement corrective action and identified 3 other identical valves that ,
were used in the plant. DHV-32.' the inlet isolation valve to DHP-18. !
was used in January. 1997, as a boundary valve for pump work and had not
exhibited any seat leakage. The other two valves. DHV-39 and 40. which 1
are the pump suction valves on the lines from the reactor coolant j
system, were also verified to be seating properly during recent. ,
maintenance evolutions. The licensee was confident that the seats in
these valves were stainless steel based on this performance, but they
still plan to inspect DHV-32 as a precautionary measure during the B
train emergency systems outage scheduled for the week of March 10, 1997.
The licensee was unable to procure a replacement valve for DHV-21 from !
the vendor quickly, and the corrosion damage coupled with high local
radiation dose rates made repair unfeasible. Consequently, the licensee ,
initiated an Operability Concerns Resolution document to investigate i
. whether the DH system could be considered operable with the valve
reassembled and the seating surface _ removed. The licensee removed all
loose seat material and corrosion 3roducts to ensure they were not
entrained into the RCS and reassem) led the valve. The investigation '
revealed the valve was not required to close for any safety function, so
its inability to close was acceptable until a permanent repair or
replacement option could be determined. The ins)ector observed that the
licensee's. primary consideration was restoring tie out of service decay ;
heat removal train in order to reestablish two redundant methods of :
decay heat removal. The inspector reviewed the licensee's 10 CFR 50.59 ;
assessment and safety evaluation and did not identify any deficiencies.
Identification of a permanent fix was still pending at the end of the '
report period.
c. Conclusion .
!
The inspector concluded the licensee displayed an appropriate priority !'
to restore a second decay heat removal system to service and performed a
thorough and conservative analysis to justify the decision to leave an
inoperable manual valve in the system and evaluate extent of condition.
The inspector assessed the licensee's performance, with respect to this l
issue in the five NRC continuing areas of concern. ,
e Management Oversight - Good i
e Engineering Effectiveness - Good ;
e Knowledge of the Design Basis - Good
. Compliance with Regulations - Good -
. Operator Performance -
N/A l
t
i
i
.
6
m.. a .n ., - .- ,,.
__
,
i
32
E1.6 $ valuation of Dranetz Test Instrument Inaccuracies on Emeraency Diesel i
'
Generator Testina
a. Insoection Scoce (37551)
The inspectors reviewed the licensee's investigation and disposition of
EDG test instrument inaccuracies contained in Operability Concerns
Resolution (OCR) Report EG-97-EDG-1A/1B and interviewed licensee
Technical Support Engineering managers and engineers,
b. Observations and Findinas
The OCR was primarily concerned with whether the EDGs exceeding maximum
load limits during full load testing and if they satisfied the
surveillance requirements (SR). ' 1.8.1.11 requires a maximum load
test at a load between 3100 and 3200 kw be 3erformed every 24 months.
This test was last done in April, 1996, on ]oth EDGs using the Dranetz
test instrumentation. However, instrument error from the Dranetz was
not factored in to the testing, and consequently the testing bands were
identical to the SR band of 3100 to 3250 kw. This oversight was
discovered by a licensee engineer in January.1997, while preparing a
post-modification test tc support corrective actions to upgrade EDG
capacity. The engineer questioned why the normal load test in
Surveillance Procedure (SP) 354A/B had a narrower test band to account
for instrument error while the maximum load test did not. Based on this
concern, the licensee initiated the OCR and performed a calculation and I
testing to determine the reliable accuracy of the Dranetz ;
instrumentation. The OCR investigation was com]lete on February. 19, i
and revealed that a calculated error of +/- 54 (w was necessary to be
a) plied to the April, 1996, testing. After review of the testing data. !
tie licensee determined that the worst case low (logged reading minus 54 ;
Kw) results for both EDG A and B were intermittently below the lower !
testing limit of 3100 Kw. The licensee conservatively determined the )
'
EDGs were previously inoperable because they had not fulfilled the
requirements of SR 3.8.1.11 and that a Licensee Event Report (LER) per i
10 CFR 50.73 was required. The A EDG had been tested satisfactorily in
January,1997, with revised Dranetz limits so it remained operable. The i
"B" EDG was scheduled to be tested the weekend of February 22. to j
restore its operability. The OCR and calculation developed an im) roved '
1
Dranetz inaccuracy of +/- 38 Kw based on a different test probe tlat was
used for this subsequent testing.
The OCR also determined that the worst case high (logged reading plus 54
Kw) results for both EDG A and B were intermittently above the upper
testing limit of 3250 Kw which also corresponds to the EDG 30 minute
rating. They determined EDG A had ootentially exceeded the limit for 6
minutes and EDG B had for 15 minutes during the April,1996, testing.
The OCR contained a detailed justification for continued o)eration in
Mode 5 that assessed the potential degradation this would lave on the
ability of the EDG to accomplish its function. The inspector reviewed
this justification, found it very detailed, and did not identify any :
-
problems with the licensee's conclusions that the EDGs were operable for
-
)
_ . . - .
,
,
.
k
l
l I
.;
l
33 !
t
Mode 5 loading with the given portion of the 30 minute rating used. The l
l licensee plans to perform outage inspections of both EDGs during their i
! current outage which will reset the 30 minute ratings to a full 30 i
minutes.
c. Conclusions l
l
'
The ins)ectors were concerned that the EDGs were potentially inoperable
since tle last refueling outage in 1996. However, the >roblem was found j
l
by the licensee while developing a functional test whici was corrective !
l action for a previously cited problem with EDG loading capacity. I
i Corrective action since discovery has been timely and EDG A has already l
, been retested. The inspector concluded the OCR involved large amount of 1
l -detailed and thorough engineering work and provided a well defined plan ;
that had operations staff involvement. Therefore, this issues an is .
considered example of a problem found as corrective action for a i
previous problem. l
The. inspector assessed the licensee's performance, with respect to this
issue, in the five NRC continuing areas of concern.
l
- Management Oversight - Good i
. Engineering Effectiveness - Good
. Knowledge of the Design Basis - Good
e Compliance with Regulations - Good .
'
- Operator Performance - Good
E2 Engineering Support of Facilities and Equipment
E2.1' Corrective Action and Reportability Issues
a. Insoection Scooe (92903)
The NRC had identified a number of concerns with corrective action and
reportability as noted in apparent violations EEI 50-302/96-12-03 and
EEI 50-302/96-19-02. As part of the followup for these issues, the
inspectors reviewed the licensee's recently issued corrective action
Procedure CP-111. Processina of Precursor Cards for Corrective Action
Program. Revision 55 relative to the definition of a DBI as defined in
the procedure.
b. Observations and Findinas
The definition of a DBI was detailed in paragraphs 3.1.3 and 3.1.4 of
Procedure CP-111. The definition given was the same as that in
Procedure CP-150. Identifying and Processing Operability Concerns and
Procedure CP-151. External Reporting Requirements.
The definition. as written in the above procedures, equated a DBI with
o>erating outside the design _ basis as referenced in 10 CFR 50.72 and 10
C:R 50.73.and indicated that a DBI exists only if a system, structure,
or component (SSCF is unable to perform its safety function in
l
__. . . .- .
_ . __. __ _ _
-
i
'!
'
- 34
2 ;
preventing or mitigating design basis events. The inspectors. pointed t
i
out that this definition appeared to be narrow, considering the ;
i definition of design basis given in 10 CFR 50.2 and the requirements of. ;
- 10 CFR 50. Appendix B. Criterion III. relative to design control. When ;
questioned by the . inspectors the Manager. Nuclear Licensing stated that - ,
- the definition was not meant to be that narrow, but he could see how it
could be interpreted that way. He stated that the definition would be i
revised to state more clearly what was intended.
c. Conclusions fi
! - The definition of a DBI. as defined in Procedures CP-111. CP-150. and
i
'
CP-151 was not broad enough to ensure that the requirements of 10 CFR ,
50. Appendix B. Criterion III.'10 CFR 50.72 and 10 CFR 50.73 would be i
met. The licensee agreed the definition did not clearly state their
- intent and stated that procedures would be revised to clarify their
.
intent. ;
The inspector assessed the licensee's performance, with respect to this
3
issue, in the five NRC continuing areas of concern- i
I
,
e Management Oversight -
Adequate :
.
.- Engineering Effectiveness - N/A .
Knowledge of the Design Basis
'
. -
N/A !
e Compliance with Regulations -
Adequate
Operator Performance
'
e -
N/A
E8.1 (Closed) VIO 50-302/96-05-05. Failure to Follow Procedures for Vodatina
- QBian Basis Documents (DBDs)
a. Insoection Scoce (92903)
.
This issue involved failure to issue a Temporary Change (TC) to the
Enhanced Design Basis Document (EDBD) and failure to ensure that TCs to i
the EDBD were incorporated into the EDBD as required by procedures. The !
'
licensee's letter of response dated August 12. 1996. was reviewed and
found acceptable. The inspectors reviewed the licensee's corrective
i actions as detailed in paragraph b. below.
,
b. Observations and Findinas
This violation was issued for two examples of failure to follow
'
procedures for updating the EDBD. In one example, a TC to the Makeup
..
System EDBD was not issued when a plant modification changed the
t Hydrogen Addition Pressure Regulator setting from 10 psig to 19.5 psig. ;
In the other example, the 12 month review of the EDBDs had not been
performed and documented, resulting in DBD Tcs not being incorporated
- within the required two year time.
1
!
4
h
.
i
em,-n.---s e e- -m e ~+,e e - =,-,. m- ,
-
,,n, -m e.-_ r , , . -
, , , , ,7._. - , ,
. . _ - . .. . ._ . . . - . . . - _ . _ . . -- - . . . _ . -.
'
l
'
!
L
l
35 ,
e
Licensee corrective actions 'were documented in Problem Report (PR) 96-
0230. The inspectors verified licensee corrective actions by reviewing. i
'
the following documents:
'
'
-
. Completed PR 96-0230. ;
I
-
Temporary Change 487 to the EDBD - which properly documented the l
Hydrogen Addition Pressure Regulator setting. !
I .
Revision 7 of NEP Procedure 216, Plant Design Basis Documents - i
!
which enhanced requirements for revising DBDs. -
- i
l
- Revision 9 of NEP Procedure 213. Design Analysis / Calculations - .
'
which required identification of plant documents affected by a !
change and tracking by the Nuclear Operations Tracking and :
Expediting System until incorporation into applicable plant
documents. j
-
On the Job Training (0JT) Session Attendance Records - which l
- documented review of the problem with applicable Design Engineers, ;
Verification Engineers Supervisors, and Configuration Management :
personnel. 1
-
Documentation that incorporation of Tcs into the EDBD was up-to-
date and that a system had been established to ensure that future
TCs are incorporated on schedule.
c. Conclusions
The inspector determined that the licensee had identified the root
causes and implemented adequate corrective actions. Based on the above
review, Violation 50-302/96-05-05 is closed.
The inspector assessed the licensee's perfcrmance with respect to this
issue, in the five areas of continuing NRC concern:
. Management Oversight - Good
. Engineering Effectiveness - Good .
- Knowledge of the Design Basis - N/A l
. Compliance with Regulations - Good i
. Operator Performance - N/A
E8.2 -(Closed) VIO 50-302/96-05-07. Inadeauate Receivino Insoections for
Battec / Charcers
(Closed) LER 96-12-02. Doeration Outside Desian Basis Caused by Battery
Charaers Havino Inadeauate Test Results AcceDted in Error
1
i
. ..1 .. .m.r _ _ . . _ _ . _ . . , _
. _ ._, . I
36
a. Insoection Scooe (92700. 92903)
The inspector followed up on the licensee's corrective actions for this
violation and LER.
b. Observations and Findinas
The inspector verified that the licensee had completed all of the
corrective actions stated in this LER and most of the corrective actions
stated in the response to this Notice of Violation, including:
-
Replacing the backup " swing" battery chargers DPBC-1E and DPBC-1F
with new chargers.
-
Incorporating additional guidance into the Nuclear Procurement and
Storage Manual (NP&SM) for receipt inspectors' review of
engineering software acceptability letters provided by
engineerir.g.
-
Adding a requirement into the NP&SM for verifying that nameplate i
data complied with Purchase Requisition requirements. l
-
Distributing a copy of the related event report (LER 96-12-02). l
along with management's expectations, to design engineers. !
procurement engineers, and receipt inspectors.
-
Updating the Preventive Maintenance Program to ensure that printed
circuit cards and capacitors are replaced in the battery chargers
on a five year frequency.
One corrective action, convening a Management Review Panel to further
review the issue, had not been completed. The inspector found that this !
item and the third item above (verifying nameplate data) were not
tracked by the licensee to assure they were accomplished. They were not
in the licensee's corrective action system or the Nuclear Operations
Tracking and Expediting System (NOTES). However, the licensee had
recently made plans to have a review panel review the corrective actions l
for essentially all of the violations from 1996, including this one. l
This violation and LER are closed.
c. Conclusions
Violation 50-302/96-05-07. Inadequate Receiving Inspections for Battery
Chargers: and LER 96-12-02. Operation Outside Design Basis Caused by
Battery Chargers Having Inadequate Test Results Accepted in Error, are
closed. The inspector noted, and commented to the licensee, that their
tracking of corrective actions for violations was incomplete. i
37
The inspector assessed the licensee's performance, with respect to this
issue in the five areas of continuing NRC concern:
. Management Oversight - Adequate
. Engineering Effectiveness - Adequate
. Knowledge of the Design Basis - N/A
. Compliance with Regulations - Adequate
. Operator Performance - N/A
E8.3 (Closed) VIO 50-302/96-05-08. Failure to Follow Purchasino Procedures
for Inverters
a. Insoection Scoce (92903)
The inspector followed up on the licensee's corrective actions for this
violation.
b. Observations and Findinas
The inspector verified that the licensee had completed the corrective
actions for this violation, as stated in their response to the Notice of
Violation, including:
-
Requiring Nuclear Engineering Design personnel to read the related
Problem Report and Nuclear Engineering Procedure 220.
-
Requiring Buyers Associates to read the Nuclear Procurement and
Storage Manual. Section 3.3.
-
Processing a Procurement Requisition Amendment.
-
Revising the associated mini-specification.
The inspector noted that the completion of all of these corrective
actions was tracked and documented in the file for Problem Report 96-
0187. This item is closed.
c. Conclusions
Violation 50-302/96-05-08. Failure to Follow Purchasing Procedures for
Inverters, is closed. The ins)ector assessed the licensee's
)erformance, with respect to t11s issue, in the five areas of continuing
4RC concern:
. Management Oversight - Good
. Engineering Effectiveness - Good
. Knowledge of the Design Basis - N/A
. Compliance with Regulations - Good
. Operator Performance - N/A
._ _ __ _ ._ _ --_ ___ _ _ _ _ . _ __. . _ . _ _ _ ___ _ _ __
,
~
!
,
38 l
.5
E8.4 (Ocen) EA 95-16. Use of Nonconservative Trio Setooints for Safety- !
i
Related Eauioment
i
a. Insoection ScoDe (92903. 37500) ;
!
As part of the continuing review of corrective actions for EA 95-16. j
the. inspectors reviewed several new instrument loop uncertainty setpoint
i
calculations. In IR 95-06 the inspectors found that the only safety-- !
l related trip setpoint calculation completed did not follow the ,
I methodology specified in Instrument Society of America (ISA) 67.04, part
l II. as referenced by instrumentation and controls Design Criteria .
Instrument-String Error /Setpoint Determination Methodology. To assess l
.the progress the licensee had made in this area, the inspector reviewed l
a sample of the most recent instrument string error /setpoints. ;
! b. Observations and Findinas
Four recent instrument loop uncertainty (instrument string error) i
setpoint calculations were reviewed. These included: j
!
I-89-0013. Containment Air Temperature. Revision 6. !
I-95-0002. SW Pump Discharge Header Pressure Calculation. ;
Revision 2 -
I-95-0001. SW Heat Exchanger Outlet Temperature Error i
Calculation. Revision 2
I-91-0004. Nuclear Service Closed Cycle Cooling Surge Tank .
Instrumentation Accuracies. Revision 3
These calculations were well documented, with well founded assumptions. l
and followed the methodology specified in ISA 67.04. Part II. as
referenced by instrumentation and controls Design Criteria Instrument
String Error /Setpoint Determination Methodology. These calculations
were a significant improvement over calculations reviewed in IR 95-06.
The inspectors selected several instrument loop uncertainty setpoint
calculations that included instrumentation in the Auxiliary Building to
ensure the temperature assumptions used in design calculations for
Instrument string error or loop uncertainty determinations were
appropriately maintained. The instruments selected were: ,
Instrument Calculation ESOPM Zone Reauired Temoerature i
SW-3-PI M95-002 Zone 11 55 - 97 F
SW-123-TI M95-001 Zone 12 65 - 97 F -
SW-124-TI M95-001 Zone 12 65 - 97 F
SW-125-TI M95-001 Zone 12 65 - 97 F
SW-126-TI M95-001 Zone 12 65 - 97 F
SW-139-LT 191-004 Zone 11 55 - 97 F
SW-228-LT 191-004 . Zone 11 55 - 97 F
,
-
. , . . , , . , . . . - . , , , _.,m.,#
.- - -- _ -. .. - . . _ - _ - - . . - -. -.-
!
!
t
39
The inspector verified that the Environmental and Seismic Qualification -
Program Manual (ESOPM) environmental assumptions were used in the-
instrument loop uncertainty setpoint calculations.
The inspector then reviewed the procedures used in the calibration of ;
these instruments to ensure that these environmental assumptions -
contained in the' instrument loop uncertainty calculations were addressed ;
in the procedure. The procedures reviewed were: ;
SP-161C Remote Shutdown Instrument Calibration. Revision 13
PT-170 Nuclear Service Closed Cooling Surge Tank (SWT-1) i
'
Instrumentation Calibration. Revision 0
The inspector found that the calibration temperatures were not specified i
and that the procedures for calibration of instruments located in the c
'
Auxiliary Building did not assure that the Auxiliary Building .
temperatures were maintained within the temperature ranges assumed in
the instrument loop uncertainty setpoint calculations. There were no ,
procedural restrictions placed to prevent calibrating or operating the
instruments at temperatures outside the temperatures assumed in the *
ESOPM or the instrument loop uncertainty setpoint calculations. ;
Additionally, there were no 3rocedures for ensuring the Auxiliary l
Building temperatures would ]e maintained within the ranges specified by i
the ESOPM or the instrument loop uncertainty setpoint calculations. ;
Therefore, the inspectors examined how ambient temperatures were ,
controlled in the Control Building and the Auxiliary Building.
Paragraph 9.7.2.7 of the Final Safety Analysis Report (FSAR) provided
4 the Operational Requirements for the Heating Ventilation and Air
4
Condition (HVAC) systems. FortheAuxiliaryBuilding, paragraph
9.7.2.7.f stated. " Minimum temperature in these areas is 60 F." For ;
"
the Control Complex. paragraph 9.7.2.7.h. stated. ". ambient is
,
maintained at 75 F".
,
. For the Control Complex, the Enhanced Design Basis Document (EDBD)
specified 75 F for winter and 70 F for summer (general design
conditions used in sizing of equipment) as operational parameters. For ,
the Auxiliary Building, the EDBD specified 60 F minimum (for freeze l
protection and personnel comfort) and 122 F maximum (for environmental l
, control for electrical equipment) as operational parameters. ,
For the Control Complex the licensee 3rovided the inspectors a graph of
recorded tem)eratures for a year, whic1 showed that the temperature in j
the Control Room had been maintained within a range of 70 F - 80 F. ;
However, based on interviews with licensee personnel and review of l
procedures, there was no program for moriitoring temperatures in the
[ Auxiliary Building.
.- 4
As noted in Section 8/7 of the EDBD. the purpose of the Auxiliary ;
Building Heating Coils (AHHE-2A AHHE-28. and AHHE-12) was to maintain ;
the Auxiliary and Fuel Handling Building at 60 F minimum. Review of !
I
i;
. - _ . _ , ._. - - . _ _
_ . . . - __
_ . _ _ _ _ __ . - _ _ . __ _ _ ._ _
,
i
i-
t
'
40
the maintenance his' tory for the Auxiliary Building heaters and ;
'
'
discussions with Engineering personnel revealed the following:
-
The heaters were not included in the Preventive Maintenance (PM)
Program. The instrument strings controlling the heaters are in
i the PM program and were being calibrated. The PMs for the -
1. instrument strings were im]lemented by Work Requests (WRs) NU
i
0266933. NU 0280142. and NJ 0305381.
-
In late 1995, as part of the boron reduction project, the. i
Auxiliary Building heaters were inspected to determine their
status and found to be not fully functional because of a number of i
blown fuses and other discrepancies. This was documented in Wrs
NU 0329662 and NU 0332052. At that time, the heaters were :
-
repaired and made fully functional. !
4 :
!
4 - In early January 1996. WR NU 0332052 was issued because heaters
.
were not maintaining Auxiliary Building temperatures at 60 F. A :
blown control fuse was replaced and the heaters made operable.
Temperatures were found to be 55' F on the second floor of the
Auxiliary Building and 52 F on the spent fuel floor. The
temperature transmitter set)oint for the heaters was 50 F. in ;
accordance with drawings. Request for Engineering Assistance -
'
(REA) 960031 was issued to change the heater setpoint to 60 F. I
since a 50 F setting was not consistent with the EDBD requirement
,
for maintaining the building at 60 F.
'
Based on the above rev'.ew, the inspectors could not determine if the
temperature in the Auxiliary Building in the past was always above the
minimum indicated in the FSAR and the EDBD. since temperatures have not
been periodically monitored. The heaters were not fully functional in
4
late 1995. However, it could not be determined how long the heaters
were not fully functional since the heaters were not included in the PM
program and temperatures were not monitored. Also, the temperature
transmitter that starts the heaters was set at 50 F. The input to the l
transmitter used the duct temperature just downstream of the air
handling unit, which was essentially the temperature of the incoming
outside air. Therefore, even if the heaters were fully functional, it
was doubtful to the inspectors that using the duct temperature as the 3
input to operate the heaters would result in the ambient temperature in l
'
the building being always maintained at 60 F minimum specified by the '
EDBD. Further, the 60 F minimum was not consistent with the ESOPM Zone
12 environmental assumptions of a 65 F minimum temperature.
, _c. Conclusions
The inspectors concluded that the licensee has made progress in
4 resolving the ITS setpoint program deficiencies. Four recent
calculations were well documented, with well founded assumptions, and
'followed the methodology specified in ISA 6'7. 04, part II. as referenced
by instrumentation and controls Design Criteria Instrument String
~
Error /Setpoint Determination Methodology. These calculations were a l
_. _ _
-
. _ _ _ ___ _
41
significant improvement over calculations reviewed in IR 95-06.
However, there were several loo) uncertainty calculations that were not
complete and were scheduled to )e completed by March 1.1997. The final
loop uncertainty determinations and instrument string error calculations
need to be reviewed by the NRC after they are issued, to complete the
followup inspection of EA 95-16.
The ins)ectors concluded that the Auxiliary Building temperature ranges
which t1e ESOPM environmental assumptions used for the instrument loop
uncertainty setpoint calculations were not maintained. Instrument
setpoint calculations assumed certain temperatures in the Auxiliary
Building for instrument calibration and operation. However, instrument
calibration procedures did not address these temaeratures: there were no
procedural restrictions in place to prevent cali) rating or operating the
instruments at temperatures outside the temperatures assumed in the
ESOPM or the instrument loop uncertainty setpoint calculations; and
there were no procedures for ensuring the Auxiliary Building
temperatures would be maintained within the ranges specified by the
ESOPM or the instrument loop uncertainty setpoint calculations. This is
a violation of design control requirements. VIO 50-302/97-01-07.
Instrument Loop Uncertainty Setpoint Calculation Assvaptions Not
Translated Into Procedures. l
The inspectors assessed the licensee's performance relative to lack of l
design control for Auxiliary Building temperatures assumed in instrument '
setpoint calculations, in the five areas of continuing NRC concern:
. Management Oversight - Inadequate
. Engineering Effectiveness - Inadequate
. Knowledge of the Design Basis - Inadequate l
- Compliance with Regulations - Inadequate
. Operator Performance - N/A
E8.5 (Closed) IFI 96-201-13. Cable Amoacity Exceeded for DHP-1A fDCP-1Al
Feeder Cable and Others
a. Insoection Scone (92903) ,
l
'
During NRC inspection 96-201. inspectors reviewed Calculation E91-0020.
Rev 0, which sized safety-related AC power cables from the ampacity and
short-circuit considerations and noted that the calculation concluded
that the cable for DCP-1A and several other cables required further
evaluation. The licensee stated at that time that evaluation of the
problem cables had been completed. However, the licensee could not find ;
the evaluation for the inspector's review, and therefore. IFI 96-201-13
was established.
UFSAR Section 8.2.2.11.a states:
In general, motor and transformer feeder cables are rated at 125
percent of full load current. In some cases, the 125 percent of
full load current rating is not met. However. as a minimum, the 4
l
l
42 i
1
.
'
cable will have a rating of 115 percent of full load current. l
This provides for motor and equipment operation at service factor
'
ratings. The reference used for cable selection is the CR-3
Electrical Design Criteria - Cable Ampacity Sizing.
.
The scope of the inspection was to determine whether the above stated
UFSAR recuirement had been met: whether ampacity calculations were done
in accorcance with published standards: and whether NRC requirements in
10 CFR 50. Appendix B. Criterion XVI. Corrective Action, were met.
b. Observations and Findinas
The licensee had three calculations which dealt with sizing cables for
ampacity. Calculation E91-0020 mentioned above covered the majority of
safety-related AC power cables. A second calculation covered sirigle
phase vital AC cables. A third calculation covered safety-related DC
cables.
The calculations were performed as part of the Electrical Calculation ,
Enhancement Program, and, for the most part. " sized" cables which were !
already installed. The ampacity tables and derating factors upon which j
the calculations were based were taken from ICEA P-46-426. Power Cable
'
Ampacities.
With regard to Calculation E91-0020. the inspector determined the
following sequence of events through discussions with licensee engineers
and document review. In 1992, the calculation was being developed, and
engineers identified that several cables did not have the required
ampacity when the generic derating factors were apalied. This did not
necessarily mean that the cables were overloaded. Jut it did mean that
further analysis was necessary. Before the calculation was issued.
Problem Report 92-0124 was initiated (in September 1992) to cover the
potential problem cables. Forty-five cables were listed as potentially
not meeting the requirements described in the scope section above [22 .
had ampacity less that full load amperes (FLA). and 23 had ampacity i
greater than FLA but less than 125 percent of FLA]. PR 92-0124 also
mentioned that there was a generic problem with any cables covered with ,
fire barrier material. The problem was that the fire barrier ampacity j
derating factors being used throughout the industry were significantly l
non-conservative. The fire barrier problem was described in NRC !
The corrective action )lan for PR 92-0124 addressed the 22 circuits
having ampacity less tlan FLA. It did not have any corrective actions
for the other 23 cables or the fire barrier problem. The fact that the
corrective action plan did not include the fire barrier problem was of
minor significance, because PR 92-0057 had already been generated for
this problem in June 1992 PR 92-0124 was closed in June 1993. The
calculation was issued during December 1993. The conclusions section of
the calculation listed 18 cables that did not meet all of the design 3
criteria and 3 cables that would meet the criteria if certain specified l
tray fill blocks were put in place within the computerized cable and 1
)
. . . . - _- ..- . . .- - - - - . - . . ...
!
_t
43 !
raceway 3rogram. There was no problem report generated for these
cables: lowever. Electrical Calculation Enhancement Program Open Item i
No. 93-ECEP-070 was established. This item was still open at the time
of this inspection. Twelve of these cables were the'same as noted in PR
92-0124. and 9 cables were different than previously noted. After NRC
Ins)ection Report 50-302/96-201 identified a concern with how the -
pro)lems were handled, the licensee initiated Precursor Card 96-3705. ;
The inspector reviewed the ampacity calculation sheets for 10 tooles 4
listed in PR 92-0124 as having ampacity less than full. load amperes.
The inspector observed that the calculation had been revised since
initiation of the PR, and these cables met all the criteria. These
cables were routed exclusively in conduit, and the originally applied ,
conduit grouping derate factor was found overly conservative upon ;
exmination of the as-built configuration. The inspector confirmed. .
thrm gh review of records, that cable CHL-1 had been replaced with cable
CHL-t. which increased the ampacity to meet the criteria. Therefore. ;
cables listed in PR 92-0124 as being problem cables but not included in :
the list of problem cables in the calculation had been properly
resolved.
From the set of 23 cables listed in the problem report that had ampacity )
between 100 and 125 percent of full load amperes, the inspector reviewed ;
the ampacity calculation sheets for three selected at random. The 1
inspector observed that these cables had been properly resolved.
Cable MTL-117 a 480-volt motor control center feeder cable, was listed
in Calculation E91-0020 ds a aotential problem and was also addressed in
Problem Report 92-124, which 1ad been closed out. The calculation
'
enhancement program open item indicated that this cable had been further
analyzed and found to meet all the criteria. The inspector walked down
. this cable route in the plant, reviewed the ampacity calculation sheet
(which had not been revised) and confirmed the load current. Based on
,
the as-built configuration and a) plication of the standard derate
factors the inspector believed tais cable had an ampacity problem. The
licensee retrieved the informal work notes upon which the conclusion
that cable MTL-117 was not a problem had been based. The licensee
reviewed the work notes during the inspection, and re)orted to the
, inspector that the calculation methodology in the worc notes was
questionable.
In Calculation E91-0020. Cable AHC-656, a 480-volt supply to control
room emergency ventilation return fan AHF-19B. was indicated to meet the
criteria for ampacity but cautioned that certain tray sections must be
limiced to less than 43 power conductors. This issue was not addressed
in a Problem Report. _The licensee's method to limit tray fill for a 4
particular tray section was to make the allowable fill equal the actual I
fill in the computer' based cable and raceway program. This technique
effectively placed a com) uter program block on adding any new cables to
the tray in question. T1e inspector identified that the com) uter
program block had not been implemented for the applicable ca)le tray
sections (tray 107, sections 7 and 8).
1
i j
J- _ . . - . - __. . - . _ - - - - _ _. - ._i
__ _ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
44
Cable MTL-67, a 480-volt supply to motor control center MCC 3AB had
sufficient ampacity for the load, but Calculation E91-0020 indicated
that the overcurrent protective device was set too high to protect the
cable. This issue was not addressed in a Problem Report. The inspector
examined the solid state trip device settings in the plant, and
concluded that the set point (320 A) was too high to protect the cable
(ampacity 237 A). The inspector also noted that a new breaker setting
sheet had been issued in January 1995 which perpetuated the old
incorrect setpoint.
c. Conclusions
Inspector Followup Item 96-201-13 raised concerns about the resolution
for potential ampacity problems identified in 1992 and 1993. This
inspector concluded that a violation of NRC requirements in the area of
corrective action (10 CFR 50. Appendix B. Criterion XVI) had occurred.
This conclusion was based primarily on the fact that Calculation E91-
0020 had identified potential problems and indicated the need for
corrective action in 1993 but the corrective action had not been
implemented and/or the same aroblems still existed in 1997. l
Specifically Cable MTL-117 lad a questionable methodology applied I
within the problem report process, the tray fill block related to Cable i
AHC-656 had not been implemented. and the protective device setpoint for l
Cable MTL-67 had not been revised to protect the cable. These cables
were randomly selected for review by the inspector, and problems were
not necessarily limited to threa cables. This is a violation of
corrective action requirements 10 50-302/97-01-09. Inadequate
Corrective Actions for Cable Ampacity.
i
The ampacity calculation performed under the Electrical Calculation i
Enhancement Program was performed according to widely accepted industry
standards. A relatively small number of cables (order of magnitude one
percent), were identified as potential problems. Therefore, the
t
original design work for sizing cables performed in 1968 to 1977 time
frame, when subjected to rigorous up-to-date analysis, was shown to be
generally sound.
Ins)ector Followup Item 96-201-13. Cable Ampacity Exceeded for DHP-1A
[DC)-1A] Feeder Cable and Others, was closed. The issues are
encompassed by, and will be tracked under, the violation described
above.
The fact that the Electrical Calculation Enhancement Program was
completed represents management's willingness to ex)end resources to
identify actively discreaancies between the design Jasis and the as-
built plant However. t1e circumstances described above indicate that
once discrepancies were identified. sufficient care was not taken to
ensure resolution. The licensee planned to resolve all ampacity
concerns before restart of the unit, as evidenced by the fact that this
was an item on the licensee's plant restart list.
- _ _ _ _ _ _ _ _ _ _ - _ _ _ .
45
With regard to the issue of cable ampacities, the inspector assessed the
licensee's performance in the five NRC continuing areas of concecn as
follows:
- Management Oversight - Adequate
. Engineering Effectiveness - Inadec uate '
. Knowledge of the Design Basis - Ac equate
. Compliance with Regulations -
Inadequate
. Operator Performance - N/A
E8.6 (00en) URI 50-302/96-201-04 Nonsafety-Related Positioners on Safetv-
Related Valves .
I
'
a. Insoect_Lon Scope (37550. 92903)
This UM involved a concern identified by the NRC during the Integrated !
Performance Assessment Process (IPAP) inspection, where safety-related
air operated valves (DCV-17. DCV-18. DCV-177. and DCV-178) used to
control cooling water flow to the decay heat removal heat exchangers l
were connected to nonsafety-related positioners. The inspector followed i
up on the licensee's corrective actions for this item,
b. Observations and Findinas
1
Licensee corrective actions were documented in PR 96-0041 and PR 96- l
0220. The inspector reviewed the corrective actions that had been (
implemented or planned to address this item. The inspector reviewed l
these corrective actions for compliance with the FSAR. Technical l
Specifications, licensee Topical Design Basis Document. design control i
procedures, operating procedures, and 10 CFR 50 Appendix R.
The licensee had prepared MAR 94-09-02-01. DC Cooling Instrument
Enhancement, to address this issue. The modification was evaluated by ,
the licensee and determined to be a restart item. However. the '
inspector reviewed the licensee's scheduling of work during the current
shutdown and noted that, based on recommendations by operations. MAR 94-
09-02-01 was being scheduled for implementation during mode 1 operation
after CR-3 restarted. The inspector noted that this implementation
schedule was not consistent with the licensee's restart evaluation.
Licensee personnel indicated that the MAR would be re-reviewed to
determine the a]propriate implementation schedule. During further
review of this %R. the inspector noted that the 10 CFR 50.59 screening
determined that a 10 CFR 50.59 safety evaluation was not required. The
inspector reviewed the 50.59 screening and determined that the screening
was weak in that it lacked adequate detail to support the conclusion
that a 10 CFR 50.59 safety evaluation was not required.
As discussed in the NRC IPAP inspection report 50-302/96-201 (Appendix
C. paragraph 3.1.5), the NRC noted that implementation of MAR 94-09-02-
01 would address the NRC's concern regarding the nonsafety-related
positioners on Valves DCV-17. DCV-18. DCV-177. and DCV-178. However,
the NRC had noted that a licensee interpretation during development of ,
- .. -- - . - . - - - - _ - . . . . -- -- - _ . .
~
~.
b
46 ;
'
the above MAR mistakenly concluded that the nonsafety-related
positioners on the safety-related valves did not violate any design . .
criteria and that failures of nonsafety-related equipment postulated to
be less than 10E-6 need not be considered. The inspector discussed with
licensee personnel the IPAP team's observation regarding interpretation ,
of the design criteria. Licensee personnel indicated that the. design !
'
criteria-in question was the Crystal River Unit 3 Topical Design Basis
Document (TDBD) for the Single Failure Criteria. Revision 1. dated ,
April 25.1994. The inspector reviewed the TDBD and noted that the IPAP
team questioned the applicability of the 10E-6 criteria included in the- '
TDBD for single failure of nonsafety-related components. This item.
remains open, and the NRC will continue to review this item to determine.
the licensee *s schedule for implementation of MAR 94-09-02-01 and
further review of the licensee s design criteria for single failure of, ,
nonsafety-related components to verify that it is consistent with NRC
requirements.
During further review of MAR 94-09-02-01, the inspector noted that the i
'
MAR identified certain operating procedures that needed to be revised as
a result this MAR. In addition to the operating procedures. identified
in the MAR. the inspector also reviewed licensee abnormal procedures
(AP) to determine if any were impacted by the MAR. One of the abnormal ;
procedures reviewed by the inspector was AP-990. Shutdown From Outside l
Control Room. Revision 8. The inspector noted that this AP provided
procedural steps for taking the plant to hot standby and then directed
operations personnel to maintain the plant in hot standby until a
specific cooldown plan was formulated. The AP did not contain steps for ,
taking the plant from hot standby to cold shutdown, and the AP did not i
provide a reference or transition to any other procedure that would be
used by the operators to take the plant to cold shutdown. The inspector
discussed this issue with licensee personnel who stated that credit was i
being taken for Operating Procedure OP-209. Plant Cooldown Revision 87, j
which was the procedure that provided guidance to the operators for i
taking the plant from hot standby to cold shutdown. The inspector I
reviewed OP-209 and noted that Enclosure 1 to the procedure provided
information concerning cooldown following a fire in the main control l
room or cable spreading room. This enclosure provided general guidance ,
for certain fire scenarios and stated that this information was intended I
to assist plant personnel in designing a s)ecific cooldown procedure l
following main control room evacuation. T1e ins)ector determined that !
the procedures (AP-990 and OP-209 being used eitler separately or in
'
conjunction with each other) did not provide adequate instructions for
taking the plant from hot standby to cold shutdown from outside the main
control room. The inspector reviewed FSAR Section 7.4.6. Auxiliary
Control Stations (Remote Shutdown System) and FSAR Section 9.8. Plant
Fire Protection Program. FSAR Section 7.4.6.5 states in part that the
design basis for the remote shutdown system is 10 CFR 50. Appendix R.
Section.L. FSAR Section 9.8.6 states that plant procedures developed in
accordance with 10 CFR 50. Appendix R. Sections III.G and III.L
establish means~to bring the plant from operating to cold shutdown. The-
-
inspector further concluded, that licensee Procedures AP-990 and OP-209 I
did not meet the requirements of 10 CFR 50. Appendix R. The guidance in
-
_ _ _ _ _
l
,
47
Procedure OP-209, which directs operations persennel to develop a
specific cooldown 3rocedure to tace the plant to cold shutdown based on
an assessment of t1e fire scenario and equipment availabil:ty, does not
meet the criteria in Section III.L of 10 CFR 50, Appendix . Section
III.L states that procedures shall be in effect to impleme,4 the
capability of being able to take the plant to cold shutdowa within 72
hours following main control room evacuation due to a fire. Licensee
personnel stated that AP-990 and OP-209 meet the intent of Section !
III.L. The inspector informed the licensee that, this issue was I
unresolved pending further NRC review of applicable SERs which discuss l
the licensee's Appendix R program. This issue will be identified as URI
50-302/97-01-08. Adecuacy of Procedures to Take the Plant from Hot
Standby to Cold Shutcown from Outside the Control Room.
c. Conclusions !
I
The inspector concluded that the schedule for implementation of MAR 94-
09-02-01 to address the issue of nonsafety-related positioners on l
safety-related valves was inconsistent with the licensee's restart aanel
recommendation. The inspector concluded that licensee Procedures A)-990
and OP-209. used either separately or in conjunction with each other,
did not provide adequate instructions for taking the plant to cold
shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following main control room evacuation due to a
fire. These procedures did not meet the requirements of Section III.L
of 10 CFR 50, Appendix R. A URI was identified pending further NRC
review of applicable SERs which discuss the licensee's Appendix R
program. ,
i
The inspector assessed the licensee's performance, with respect to this
issue, in the five areas of continuing NRC concern:
- Management Oversight - Adequate
. Engineering Effectiveness - Good
. Knowledge of the Design Basis - Good
. Compliance with Regulations -
Inadequate
- Operator Performance - N/A
E8.7 (Closed) Inspector Followup Item (IFI) 50-302/95-15-01. Desian
Reauirements for Nitrocen Overoressure
a. Insoection Scope (92903)
This IFI dealt with a unique feature of the Crystal River nuclear
service water system, a surge tank that was pressurized with nitrogen
and not located at the highest point in the system. The function of the
tank appeared to be for ensuring the system pressure remained at 60 psi.
Following Inspection 50-302/95-15 the licensee reviewed the system
design basis and determined that the setpoints associated with the surge
tank should be verified. This IFI was reinspected in inspection report
50-302/96-21: however, the IFI was left open pending the review of the
calculations and validation that the alarms were changed.
l
- -. .... - . .. .-. ..-.-. . - ._. -. - . - - - . _ - . . . - ..
!
!
1
48 j
b. Observations and Findinas l
The inspector reviewed the applicable calculations: !
!
, M95-0035, SW System Inventory Transient Analysis Revision 1. !
! ~
M93-0018. Nuclear Service Closed Cycle Surge tank (SWT-1) l
Volume. Revision 1. ;
.
M92-0019. SW Surge Tank Tie-in Pressure Drop Analysis, Revision ;
, 3. 191-0004, Nuclear Service Closed Cycle Surge Tank l
Instrumentation Accuracies. Revision 3. !
1 . i
Calculation M95-0035 demonstrated that the as-found setpaints for SW-
'
,
- 134-PSI and S'4-137-LS were not appropriate. The setpoints for these l
'
l instruments were changed in 191-0004. These setpoint changes were
- included in Surveillance Test PT-170, Nuclear Service Closed Cycle Surge l
Tank (SWT-1) Instrument Calibration. l
'
There was' one area of confusion regarding the units of the exact
location _of the SW Surge Tank High Level alarm. The calibration
Procedure PT-170 described the set Joint as 109'6". The annunciator
'
.
alarm Procedure ESAB-A-01-08 descri)ed the location as 10'0". The
2
calculation 191-004 described the location as 109'6" plant elevation. !
'
! 11*6" tank elevation, or 10' transmitter elevation. Calculation M95-
- 0035 Assumption 5.6. tank drawing on page 22 of 23. tank drawing on page
- 10 of.10 describes the Hi-alarm setpoint as 111'-0". The November 22,
1995, letter IOC NED95-0691 described the setpoint changing from 110'6"
to 109'6". Finally, the vendor Drawing 5-315-D1. listed the normal
water level at 109'6" (Normal operating level - Tank bottom elevation +
tank height - distance from top of tank to normal water level) = (109'6"
- 98' + 16'- 4'6"). This level was at the high alarm setpoint. The
- inspector was informed that although this drawing was available through
'
document control, it was an original tank drawing and was not used for
L any specific purpose.
c. Conclusions
The inspector found that there were four separate level measurement
<
systems used to refer to this setpoint. These were:
a
(1) Distance from an arbitrary plant datum point
. (2) Distance from the floor of the room in which the tank is located
(3) Distance from the inside edge of the bottom of the tank
,
(4) Distance from an arbitrary zero in the tank
The inspector concluded that, while the four different elevation systems
used to refer to the same point, other than presenting the possibility
for future errors there were no consequences for this particular
calculation or its resulting setpoint. The inspector concluded that the
licensee had ccmpleted the loop uncertainty calculation and
l
. -- - .- -- - .,
49
appropriately calibrated the affected instrumentation, and that these
actions adequately addressed the portions of IFI 95-15-01. Design
Requirements for Nitrogen Overpressure, that were not reviewed or closed
in IR 50-302/96-21.
The inspector assessed the licensee's performance, with respect to this
issue, in the five areas of continuing NRC concern:
Management Oversight - Management oversight was judged to be good, in
that, there was management involvement throughout the project, and when
small procedural concerns were identified they were dealt with in an
expeditious manner.
Engineering Effectiveness - The engineering was judged as good. The
conclusions were acceptable and the new setpoints were technically sound
and were appropriately translated into procedures.
Knowledge of Design Bases - The licensee's design basis knowledge was
judged as adequate. The reason that this IFI was opened was because
there was not a com]lete understanding of the systems design basis. At
the conclusion of t11s calculation the licensee had reconstructed the
design basis for the SW surge tank. One aspect of calculation. 191-
0004. Nuclear Service Closed Cycle Surge Tank Instrumentation
Accuracies. Revision 3 that was not appropriately addressed was the
translation of the associated nuclear service closed cycle surge tank
Auxiliary Building instrumentation accuracies into appro]riate
calibration procedures. This is addressed in paragraph E8.4.
Compliance With Regulations - The utility demonstrated the appropriate
amount of regulatory sensitivity for this issue. There was reasonably
timely work, the calculations were accurate, and the results were
available for review. The inspector judged this area as good.
Operator Performance - There was limited operations involvement in this
3roject. However, as noted above there were inconsistencies in units
)etween the annunciator response procedure and the calibration
procedure. There were apparently discrepancies between the actual level
and the level reported in an original vendor drawing. However, in spite
of this potential confusion, the appropriate levels appear to be on the
installed equipment and in the alarm response procedure, the area of
operations was judged as adequate.
. Management Oversight - Good
. Engineering Effectiveness - Good
. Knowledge of the Design Basis - Adequate
. Compliance with Regulations - Good
. Operator Performance - Adequate
--. - . - . -
,
50
E8.8 i0oen) VIO 50-302/96-09-07. Inadeauate Corrective Action for
Lmolementation of EFIC Task Force Recommendations
a. Inspection Scoce (37550. 92903)
This violation involved failure of the licensee to take adequate and ,
timely corrective actions to implement recommendations from the l
Emergency Feedwater Initiation and Control (EFIC) task force. The
inspector followed up on the licensee's corrective actions for this j
violation.
b. Observations and Findinas ,
The inspector reviewed the corrective actions specified in the .
licensee's response to this violation. The inspector reviewed these )
corrective actions for compliance with the FSAR. TS, and applicable ;
licensee procedures. The inspector noted that some of the corrective l
actions specified in the response had been implemented. Corrective l
actions implemented included all Requests for Engineering Assistance
(REA), which recuested a plant modification, being reviewed and approved ;
by the Plant Mocification Review Group (PMRG): a list of high priority l
'
modifications was being maintained by the PMRG: high priority EFIC/EFW
issues were being addressed during the present shutdown: and additional
resources (permanent and contract personnel) were added to the ;
engineering organization to ensure that high priority tasks were being
worked. The inspector noted that the modifications to address the high
priority EFIC/EFW issues had not been implemented.
During review of the corrective actions, the inspector noted that many
of the EFIC Task Force recommendations were not included on the .
licensee's restart list. The inspector questioned licensee personnel as l
to whether the EFIC Task Force recommendations had been or would be l
evaluated against their restart criteria. This question was further 1
amplified when the inspector noted that precursor card (PC) No. 97-0595
was initiated on January 28, 1997, which questioned whether one of the
EFIC Task Force recommendations should be evaluated as a restart
restraint during the current shutdown rather than the scheduled
implementation during Refuel 11. Licensee personnel indicated that PC
97-0595 would be evaluated against their restart criteria by the restart
panel. This item remains open )ending further review of the licensee's
evaluation of PC 97-0595 and otler EFIC Task Force recommendations by
the restart panel. l
c. Conclusion
The inspector concluded that the licensee had implemented a number of
corrective actions to address this violation. However, not all EFIC
Task Force recommendations had been reviewed by the licensee using their
restart criteria.
l
I
1
_ ___ __ __ ._ _ . _ _ _ _ . - _ _
.
51
The inspector assessed the licensee's performance, with respect to this
issue. in the five areas of_ continuing NRC concern:
- Management Oversight - Adequate
- Engineering Effectiveness - Good
- Knowledge of the Design Basis - N/A
e Compliance with Regulations - Good
. Operator Performance - N/A
E8.9 (Ocen) VIO 50-302/95-21-03. Failure to Isolate the Class IE from the Non
Class IE Electrical Circuitry for the Reactor Buildina Purae and Mini-
?urae Valves
a. Insoection Scoce (37550. 92903)
This violation involved failure of the licensee to isolate Class IE from
Non Class IE electrical' circuitry for the reactor building purge and
mini-purge valves. The inspector followed up on the licensee s
corrective actions for this violation.
b. Observations and Findinas
The inspector reviewed the corrective actions specified in the
licensee's response to this violation. The corrective actions were
reviewed for compliance with the FSAR. TS, and applicable licensee
procedures. The inspector noted that some of the corrective action
. specified in the response had been completed. Other corrective actions
involved implementation of modifications to address the issue. Some of
the modifications had been implemented. During review of the corrective
actions, the inspector noted that the licensee's evaluation of
alternatives to the present non-isolated design of the control circuits
for reactor building purge valves AHV-1A and AHV-1D had not been
completed by the scheduled date of December 20, 1996. The new schedule
date for completion of the evaluation was changed to May 1998. The
inspector discussed this change with licensee personnel who indicated
that the schedule change was due to an increase of other higher priority
issues such as EFIC/EFW and EDG loading. The inspector also questioned
whether this issue had been evaluated as a potential restart issue and
licensee personnel indicated that the issue had not been evaluated by
their restart panel. This item remains open.
c. Conclusion
The inspector concluded that the licensee has completed some of the
specified corrective actions to address this issue. However, due to
workload and higher priority issues related to the EFIC/EFW and EDG
loading, the scheduled completion date for other-corrective actions was
not met and the completion date was extended.
._
52
The inspector assessed the licensee's performance, with respect to this
issue, in the five areas of continuing NRC concern:
. Management Oversight - Adequate
. Engineering Effectiveness - Adequate
+ Knowledge of the Design Basis - N/A
+ Compliance with Regulations - Good
. Operator Performance - N/A
E8.10 (Ocen) NRC Generic letter 96-06. Assurance of Eauioment Doerability and
Containment Intearity Durina Desian-Basis Accident Conditions
a. Insoection Scooe (92903)
GL 96-06. issued September 30, 1996, requested certain actions from all
operating nuclear power reactors relative to the following safety-
significant issues:
-
During a loss of coolant accident (LOCA) or a main steamline break
(MSLB). cooling water systems serving the containment air coolers
may be exposed to waterhammer for which they were not designed.
-
During LOCA and MSLB scenarios, cooling water systems serving the
containment air coolers may experience two-phase flow conditions
that were not considered in heat removal assumptions resulting in
system design and operability questions.
- Thermally induced overpressurization of isolated water-filled
piping sections in containment could jeo]ardize the ability of
accident-mitigating systems to perform t1eir safety functions and
cold lead to breach of containment integrity via bypass leakage.
In this inspection, the inspectors examined the licensee's actions to
date for evaluation and corrective actions relative to thermally induced
overpressurization of isolated piping sections.
b. Observations and Findinas
GL 96-06 requested that licensees determine if aiping systems that
penetrate the containment were susceptible to tiermal expansion so that
overpressurization of piping could occur. If systems were found to be
susceptiole, licensees were expected to assess the operability of
affected systems and take rcrrective action as appropriate. Licensees
were requested to submit a written summary report within 120 days of the
date of the GL letter stating the actions taken in response to the
requested actions, including conclusions reached relative to
susceptibility for overpressurization of piping that penetrates the
containment. the basis for continued operability of affected systems,
and corrective actions that were implemented or planned.
The licensee's 120 day response was submitted on January 27, 1997. The
response detailed the review performed to determine containment
.- . .- - . . - . - . - - ..
f
i
'
53 !
penetration piping susceptible to overpressurization. For the .
containment penetration process piping susceptible to ,
overpressurization, the licensee has designed and is installing rupture -i
discs and expansion chambers to allow for expansion of the process ;
fluid. For all susceptible penetrations, except SW system penetrations i
314 and 318 rupture discs will be enclosed in expansion chambers j
located outside the containment. For-SW 2enetrations 314 and 318, t
rupture discs will be installed inside tie containment without expansion' '
'
chambers. The rupture discs will be connected to the process piping
with 3/8" diameter tubing. In addition-to installation of expansion >
chambers for containment penetration piping, the licensee was still !
evaluating the need for additional relief valves in other piping. -
'
Although, based on the size of piping (tubing) between process piping
and the expansion chambers, the expansion chamber would be exempt from
ASME Section XI requirements. the licensee applied ASME Section XI
requirements to the design, fabrication and installation of the ;
expansion chambers. This resulted in the use of USAS B31.1. 1967 l
Edition and B31.7. 1969 Edition as the applicable Codes. ]
The inspectors observed the following relative to design, procurement ,
and installation of the expansion chambers: I
-
Engineering - The inspectors reviewed the approved MAR 96-10-04-
01, including the 10 CFR 50.59 Evaluation and the Installation
Instructions.
During review of the MAR package the ins)ector noted that the
Inservice Inspection (ISI) Requirements cleck sheet had not been
properly completed. The ISI check sheet is used during the MAR
development and review arocess to have ISM personnel review the
MAR package to ensure tlat ISM requirements are adecuately
addressed. For MAR 96-10-04-01, the check sheet hac been signed
by the Nuclear ISM Specialist indicating his review, but he failed
to check-mark the ISI Requirements as " Acceptable" or -
" Unacceptable". For this case the failure to complete the ISI
Requirements form 3roperly was not that significant since no ISI
was required and t1ere was a later required review for ISI
requirements at the time of issue of the installation work
packages. However, issue of the MAR package without the ISI check
sheet being properly completed indicates a weakness in the MAR
review and approval process. The licensee issued a Precursor Card '
to document and take appropriate corrective actions for this
weakness. Also, prior to this inspection, the licensee had
identified the need to strengthen-their procedures in the area of
ISI review of MAR packages. Procedure revisions were in process.
For containment penetrations 314 and 318, which will have rupture
discs installed inside the containment without expansion chambers,
the inspectors questioned the licensee relative to the need to
provide an exclusion zone around the rupture discs to ensure that
future modifications do not install equipment where it might be
. . -.
54
damaged in the event of a rupture disc rupture. Engineering
personnel stated that the need for an exclusion area would be
evaluated and added if considered necessary.
-
Procurement - Sample records from Purchase Ceder F810203D
3rocurement package were reviewed. Records raviewed included: FPC
Receiving Inspection Report and Inspection Plan: Welding Services.
Inc. (WSI) Certificate of Conformance: Fabrication Traveler
36077001 for chambers MURS-1 and MURS-2: Weld Data Sheets for
Welds SW-1. 2. 3. 4. 5. and 6: radiographic film reader sheets for
chambers CARS-1. MURS-1. CFPS-1. SFRS-1 and DHRS-1: certification
for NDE materials: and FPC letters of approval for Welding
Specifications. NDE Procedures, and welder qualifications.
-
Installation Activities -
The inspectors observed portions of the welding and liquid
penetrant (PT) examination for weld CA-85-86 on WR NU 0339386,
welds CA-85-85 and CA-85-127 on WR NU 0339390, and weld CA-85-149 l
on WR NU 0339392. In addition, for the welds observed, welder
qualification records, weld material test reports. NDE examiner
certification records, and penetrant material test reports were
reviewed. I
!
c. Conclusions I
The inspector concluded that the licensee was performing detailed ;
evaluations and developing solutions for the issues identified in GL 96-
06. Overall, the MAR package, including the 10 CFR 50.59 evaluation,
for design, procurement, and installation of the containment penetration
process piping expansion chambers was detailed and well documented,
demonstrating good Engineering performance. Procurement activities were
detailed and well documented. Welding and inspection work activities
associated with installation of the expansion chambers were good with
detailed, neat, and well-maintained documentation.
One weakness was identified relative to completion of the ISI
Requirements check-sheet.
The inspector assessed the licensee's performance, with respect to this
issue, in the five NRC continuing areas c' concern:
. Management Oversight - Good
. Engineering Effectiveness - Good
. Knowledge of the Design Basis - Good
. Compliance with Regulations - Good
. Operator Performance - N/A
55
IV. Plant Support
F3 Fire Protection Procedures and Documentation
F3.1 Fire Protection System Recirculation Limits
a. Insoection Scooe (71707)
The inspectors reviewed the licensee *s response to improper control of
fire pump recirculation flow that resulted in a condition where all
three fire pumps were rendered inoperable.
b. Observations and Findinas
On January 17, 1997, the licensee placed motor-driven fire service pump
(FSP) 1 in service per Operating Procedure (0P) 880. Fire Service
System. Revision 9. to recirculate both fire service tanks. This
implemented Operation Instruction (01) 13. Adverse Weather Conditions.
Revision 1. for potentially freezing temperatures. The two other fire
pumps. diesel-driven FSP-2A and FSP-2B, were both rendered ino)erable on
January 17 because both fire pump building fans had to be disa) led and
placed in pull-to-lock as required by 01-13. This removed the
combustion air supply for the diesel FSPs so they had to be declared
inoperable. On January 18 a concern was raised about the continued
lifting of the FSP-1 discharge relief valve due to the low recirculation
flow of 600 gpm and corresponding high discharge pressure. This was a
concern because the relief valve water was directed to the turbine i
building sump and required processing prior to being released offsite. l
The recirculation flow was raised to 2000 gpm after consulting with a
fire protection engineer to lower the pressure and reseat the valve.
Approximately five hours later, oncoming shift operators questioned the
impact of the higher recirculation flow rates on operability of FSP-1. i
Although OP-880 only contained a note to ensure recirculation flow does
not exceed 2000 gpm. further consultations with fire protection :
engineers revealed that any flow above 600 gpm rendered the pump
'
inoperable due to the lower discharge pressure and flow diverted from
the header for recirculation. Consequently, all 3 FSPs were inoperable
for over five hours.
Shift supervision immediately recognized the seriousness of this
situation and restored the two diesel FSPs to operable, initiated an 01-
12 investigation, and developed a Short Term Instruction to provide
interim recirculation flow rate guidance. PC 97-357 was initiated to
perform a root cause investigation, and the Director of Nuclear Plant
Operations prioritized this issue by placing it on his "short fuse"
list. The root cause evaluation and corrective actions were developed
,
by January 31. Although subsecuent revisions delayed issuance of it
until February 5 and the licensee's Corrective Action Review Board
(CARB) did not review the event until February 18. the inspector noted
the licensee's root cause determination and corrective action plans were
adequate. The licensee determined that the 600 gpm recirculation limit
was not contained in procedures and was not reflected in the Fire
56
Protection Plan. Their investigation revealed several other
-
communication and procedural problems which they adequately addressed.
Consequently, this licensee identified violation meets the requirements
outlined in Section VII of the Enforcement Policy and will not be cited; f
This issue is identified as Non-Cited Violation NCV 50-302/97-01-03. !
Inadequate Fire System Recirculation Procedure. i
t
c. Conclusion' ;
.
The inspectors concluded that the subsequent operations shift exhibited '
l
a questioning attitude that resulted in the discovery of this condition. .
Corrective action was implemented in a timely manner although the delay ;
'
for the CARB to review the corrective action plan left room for
improvement. The inspectors had concerns about the lack of guidance in ;
the procedures for the operators to make operability determinations but i
were satisfied.that the licensee's corrective actions would address j
them.
R1 Radiological Protection and Chemistry (RP&C) Controls ;
R1.1 General Comments (71750) i
The inspectors conducted routine tours of the licensee's radiologically ;
controlled areas (RCA) and verified radiological controls such as
control of locked areas. surveys and postings, and access controls. The
inspectors routinely observed status of the radiation monitoring and
meteorological systems. Chemistry results were typically reviewed daily
during normal work days. Generally good performance was noted in these
areas. Highradiationareaswereciearlymarkedandlocked.
The inspectors observed daily priority is placed on tracking of
radiological exposure against outage goals. Although the goal and
exposure amount occasionally did not agree, the licensee was actively
refining their 3redictions and results were improving. The inspectors
also observed tlat the licensee accomplished a notable achievement. in
that the reactor building was decontaminated sufficiently to relax some
protective clothing requirements for tours and walkthroughs. The
inspectors did not identify any deficiencies in the areas of
radiological controls or chemistry.
51 Conduct of Security and Safeguards Activities
S1.1 Protected Area Security Breach
a. Insoection Scooe (71750)
On January 30. 1997, at 6:45 p.m. the licensee discovered a penetration
path into the protected area via a breach in a condenser waterbox. The
inspector reviewed the licensee's investigation documentation in PC 97-
0053 and Security Information Report 10815 and interviewed licensee
personnel, j
i
5
!
. - , , _ _ . ,, ,_
. _ _ , . .- . . - . ..-.- - - . ._ -
_
57
b. Observations and Findinas
The breach was discovered by an alert security officer who questioned
maintenance work that had removed components he did not recognize. The !
breach was immediately posted as a compensatory measure and security
force members initiated efforts to determine the scope of the problem.
They determined that the breach had existed for aaproximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
and was in excess of the allowable security plan areach size, so it did
constitute a protected area breach. The inspector noted that the i
maintenance work was stopped and the security guards performed an
inspection of the vital and protected areas to ensure they were not 3
compromised. The licensee reported the event as discussed in paragraph
01.2 and was developing a written Licensee Event Report. The inspector
determined that security 3ersonnel had been properly notified of the
maintenance work, and it lad been evaluated for the potential to cause a
breach. However following the removal of the com>onents the security 1
officer expressed a concern that a penetration pati was opened that was
not recognized by the licensee. Consequently, appropriate compensatory
measures were not implemented. The licensee had a similar penetration j
3athway via a waterbox breach on November 1.1996. which was identified
)y the NRC as Escalated Enforcement Item 50-302/96-18-04. The
corrective actions for that item and the January 30 occurrence were
discussed at an Enforcement Conference held at the NRC Region II Office
on February 14. 1997. The resulting enforcement action EA 97-012 was
issued on February 28. 1997. The above violation is an additional
example of violation No. A(4)(01043) which was issued in EA 97-012. The
inspectors determined that those corrective actions, which were not yet
fully implemented, would be adequate to address the problems. The
inspector also observed that licensee management assembled an effective
investigation team the next day to assess the potential for any other
penetration pathways although their expectation was that this effort
would be initiated by shift management at the time of occurrence.
c. Conclusions l
The inspectors identified the January 30 waterbox breach as a second
example of violation No. A(4)(01043) which was issued in EA 97-012. The
inspector concluded the licensee security staff displayed a questioning
attitude to discover the breach, but the licensee's initial
investigation was not prioritized properly as discussed above and in 1
paragraph 01.2. The inspectors concluded the licensee's planned j
corrective actions were appropriate to prevent recurrence. !
S1.2 Security Event Loa Audit (71750)
The inspector audited the Security Event Log (SEL). required by Appendix
G of 10 CFR 73. for the first. second, and fourth quarters of calendar
year 1996. The inspector verified selected problems were adequately
logged and that log items were routinely reviewed by security
management. The ins)ector reviewed the Security Information Reports
(SIR) associated wit 1 several of the logged problems in detail and did
not identify any problems. These events included problems such as vital !
i
l
_.
. - . - -- - - - .- . = . . -. - .. - -
h
!
!
58
l
area doors left unsecured, security badges inadvertently removed from :
l the site, and human error events. The inspector also observed that a PC :
document was generated on initiation of each SIR to include the problem ,
in the plant wide corrective action program. The inspector concluded :
this was a good practice for both management visibility and trending ,
I purposes. The inspector did not identify any problems with the number :
i
of events and observed that the trends in some areas such as unsecured i
vital doors were notably improved. The inspector concluded the licensee :
was appropriately maintaining the Security Event Log. {
V.Manaaement Meetinas !
X1 Exit Meeting Summary l
The inspection scope and findings were summarized on January 31. February 14 :
'
and February 27, 1997. Proprietary information is not contained in this
report. Dissenting comments were not received from the licensee. ;
X2 Pre Decisional Enforcement Conference Summary
l
X2.1 An Enforcement Conference was held on January 24, 1997, in Region II to i
discuss apparent violations associated with the Emergency Diesel
tienerators, the Emergency Feedwater System and containment penetratioris.
Results of this meeting were issued as an escalated enforcement action
on March 12. 1997.
X2.2 An Enforcement Conference was held on February 14, 1997, in Region II to
discuss apparent violations associated with Security. These apparent
violations are discussed in Inspection Report 50-302/96-18. and
results of this meeting were issued as an escalated enforcement
action on February 28, 1997.
X3 Management Meeting Summary
X3.1 A public meeting was held on site at Crystal River February 12. 1997.
The purpose of the meeting was to discuss items related to restart. A
separate meeting summary was issued on February 19. 1997.
PARTIAL LIST OF PERSONS CONTACTED
Licensees
K. Baker. Manager. Nuclear Configuration Management
D. Bates. Manager. Quality Systems
J. Baumstark. Director. Quality Programs
-P. Beard. Senior Vice President. Nuclear Operations
.G. Becker. Manager. Nuclear 0)erations
.J. Cam) bell. Assistant Plant )irector, Maintenance
-W. Con (lin. Jr.. Director. Nuclear Operations Materials and Controls
J. Cowan. Vice President. Nuclear Production
D. Daniels. Manager. Nuclear Safety Assessment Team
R. Davis. Assistant Plant Director. Operations
._ .
59
D. DeMontfort. Manager. Nuclear Operations ,
M. Donovan. Supervisor. Rapid Engineering Response Team ,
B. Gutherman Manager. Nuclear Licensing l
G. Halnon. Assistant Director. Nuclear Operations Site Support
B. Hickle, Director, Nuclear Plant Operations ,
J. Holden. Director. Nuclear Engineering and Projects j
R. Knoll. Supervisor. Nuclear Engineering
H. Koon. Manager. Nuclear Production and Nuclear Outage
D. Kunsemiller. Director. Nuclear Operations Site Support
J. Maseda. Manager. Engineering Programs
R. McLaughlin. Nuclear Regulatory Specialist
D. Poole. NGRC Member
D. Roderick.-Manager.-Outage and Work Controls
W. Rossfeld. Manager. Site Nuclear Services
J. Stephenson. Manager Radiological Emergency Planning
F. Sullivan. Manager Nuclear Engineering Design
J. Terry. Manager. Nuclear Plant. Technical Support
J. Tunstill. Senior Nuclear Licensing Engineer
D. Watson. Manager. Nuclear Security
R. Widell. Director. Nuclear 0)erations Training
D. Wilder. Manager. Radiation protection and Chemistry
R. Yost. Manager. Nuclear Quality Assessment
NRC
B. Crowley. Reactor Inspector. Region II (January 27 through 31. 1997.
February 10 through 14, 1997)
P. Fillion. Reactor Inspector. Region II (January 27 through 31. 1997.
February 10 through 14, 1997) !
F. Hebdon. Director. Directorate 11-3 NRR (February 12, 1997) l
J. Jaudon. Director. Division of Reactor Safety. Region II (February 11
through 12. 1997)
K, Landis. Branch Chief, Region II (January 27 through 29, 1997)
L. Mellen. Project Engineer. Region II (January 27 through 31, 1997. February
10 through 14. 1997)
L. Raghavan. Project Manager NRR (February 10 through 13, 1997)
R. Schin. Reactor Inspector. Region II (January 27 through 31. 1997. February
10 through 14. 1997)
M. Thomas. Reactor Inspector. Region II (January 27 through 31, 1997. February
10 through 14, 1997)
INSPECTION PROCEDURES USED
IP 37550: Engineering i
IP 37551: Onsite Engineering j
'
IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving and
Preventing Problems ;
IP,61726: Surveillance Observations 1
, IP 62703: Maintenance Observations i
IP 62707: Conduct of Maintenance i
"
IP 71707: Plant Operations
IP 71750: Plant Support Activities
_ _.. - .__ _ __ _ . - _ _ . . _ . _ _ _ --. - __ _
- - - - . - . - - - - - . . - . - . . - - - . - . - . - - .
,
!
r
i
i
60 !
\
-IP 9h'00: Onsite LER Review I
IP 92901: Followup - Operations !
IP 92902: Followup - Maintenance !
IP 92903: Followup - Engineering - i
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened i
i
lypf Item Number Status Descriotion and Reference !
i
VIO 50-302/97-01-01 Open Inadequate Clearance Tagging Requirements. ;
.(paragraph 01.3) l
VIO 50-302/97-01-02 Open -Failure to Follow Procedures, Resulting in !'
an lnadv& tent Emergency Diesel Generator
Start. (paragraph 01.6)
VIO 50-302/97-01-04 Open Failure to Perform TecHeal Specification I
Surveillance for Spent M Pool Level. i
(paragraph M1.1) ,
URI 50-302/97-01-06 Open HPI System Design, Licensing Basis, and TS
Concerns. (paragraph E1.3) ;
'
VIO 50-302/97-01-07 Open Instrument Loop Uncertainty Setpoint
Calculation Assumptions Not Translated
Into Procedures. (paragraph E8.4)
URI 50-302/97-01-08 Open Adequacy of Procedures to Take the Plant
from Hot Standby to Cold Shutdown from
Outside the Control Room. (paragraph E8.6)
VIO 50-302/97-01-09 Open Inadequate Corrective Actions for Cable
Ampacity. (para 0raph E8.5)
Closed
lysg Item Number Status Descriotion and Reference
NCV 50-302/97-01-03 Closed Inadecuate Fire System Recirculation
Procecure. (paragraph F3.1)
NCV 50-302/97-01-05 Closed Inadequate Surveillance Procedure to Test
Operability of Toxic Gas Chlorine
Detectors. (paragraph M1.5)
VIO ~ 50-302/96-05-01 Closed Failure to Follow Procedures to Initiate
Corrective Action for Bent Main Steam Line
Hangers. (paragraph 08.1)
VIO 50-302/96-05-05 Closed failure to Follow Procedures for Updating
\
.- . . _- - . .- - ,
. . _ ._ _ _ . - - . _ _ _ _ _ _ . ._ _ _ _ __ _ . _ . _ _ _ . . _ _ . _ . . . . _ ._._
!
!
!
!
61
f
- DBDs. (paragraph E8.1) j
,
t VIO 50-302/96-05-07 Closed Inadequate Receiving Inspections for l
Battery Chargers. (paragraph E8.2) }
.
, VIO 50-302/96-05-08 Closed Failure to Follow Purchasing Procedures j
for Inverters. (paragraph E8.3) -
LER 50-302/96-12-02 Closed Operation Outside Design Basis Caused by
Battery Chargers Having Inadequate Test ;
Results Accepted in Error. (paragraph i
'
E8.2) !
.
IFI. 50-302/95-15-01 Closed Design Requirements for Nitrogen
Overpressure. (paragraph E8.7)
l ,
IFI '50-302/96-201-13 Closed Cable Ampacity Exceeded for DHP-1A [DCP- l
1A] Feeder Cable and Others. (paragraph !
- E8.5) l
1
i
'
URI 50-302/96-05-02 Closed Design Concerns with the Main Steam Lime i
Hangers Used in Seismic and Other Dynamic ,
Load Applications. (paragra)h 08.1)
. NCV 50-302/97-01-10 Closed Inadequate Design Control ion-Safety
Related Components in Safety Related
)'
Applications - Two Examples: Thyrite Surge
Protection Device. Operator and Controller
,
for MUV-103. (paragraph E1.2)
l D.lic_Ultd
1
l- Iyng Item Number Status Descriotion and Reference
,
4
URI 50-302/96-17-03 Open Failure to conduct required technical
.
specification surveillance testing on
safety related circuitry. (paragraph M8.1)
! URI 50-302/96-201-04 Open Non Safety-Related Positioners on Safety-
i Related Valves. (paragraph E8.6)
VIO 50-302/96-09-07 Open Inadequate Corrective Actions for
f Implementation of EFIC Task Force
Recommendations (paragraph E8.8)
- VIO 50-302/95-21-03 Open Failure to Isolate the Class IE from the
Non Class IE Electrical Circuitry for the
< Reactor Building Purge and Mini-Purge
,
Valves. (paragraph E8.9)
1
'
EA 50-302/96-016 Open Use of Nonconservative Trip Setpoints for
Safety-Related Equipment. (paragraph E8.4)
,
c .--~ - , _
_m_. , ___ , . . , _ , 4 ., ,_., , _ , _ _ _ . ,,__y _ _ -,m. ... . , . _ iw -
_ __ _ . . _. __
i
,
62
EA 50-302/97-012 Open Failure to Maintain Protected Area !
Barriers. Second Example of EA 97-017.
Violation A(4)(01043). (paragraph S1.1)
LIST OF ACRONYMS USED
AI - Administrative Instruction '
AP - Abnormal Procedures
AR - Air Removal i
BAST - Boric Acid Storage Tank c
CARB - Corrective Action Review Board :
CCHE - Control Complex Habitability Envelope
CFR - Code of Federal Regulations
CFT - Core Flood Tank
CREVS - Control Room Emergency Ventilation System i
CR3 - Crystal River Unit 3
CT - Current Transformers
DBD - Design Basis Document i
DBI - Design Basis Issue l
DH - Decay Heat
DHP - Decay Heat Pump i
DHV - Decay Heat Valve i
DNPD - Director Nuclear Plant Operations '
EA - Enforcement Action
ECCS - Emergency Core Cooling System
EDBD - Enhanced Design Basis Document
EDG - Emergency Diesel Generator
EEI - Escalation Enforcement Item
EFIC - Emergency Feedwater Initiation and Control
ES - Engineered Safeguards
ESOPM - Environmental and Seismic Qualification Program Manual
FLA - Full Load Am)eres
FLUR - First Level Jndervoltage Relays
FME - Foreign Material Exclusion
FPC - Florida Power Corporation
FSAR - Final Safety Analysis Report
FSP - Fire Service Pump
FTI - Framatome Technologies, Inc.
GL - Generic Letter
HPI - High Pressure Injection
HVAC - Heating Ventilation and Air Condition
I&C - Instrumentation and Control
IFI - Inspection Followup Item
IPAP - Integrated Performance Assessment Process
ISA - Instrument Society of America
ISI - Inservice Inspection
KW - Kilowatts
LER - Licensee Event Report
LOCA - Loss of Coolant Accident
LOOP - Loss of Offsite Power
LPI - Low Pressure Injection
63
MAR - Modification Approval-Record
MCAP - Management Corrective Action Plan
MSLB - Main Steamline Break i
MUV - Make-up Valve
NCV - Non-cited Violation
/ NEP - Nuclear Engineering Procedure :
NGRC - Nuclear General Review Committee
NOTES - Nuclear Operations Tracking and Expediting System
NOV - Notice of Violation
NPSH - Net Positive Suction Head
NP&SM - Nuclear Procurement and Storage Manual
N0A - Nuclear Quality Assessments
NRC - Nuclear Regulatory Commission
NRR - Office of Nuclear Reactor Regulation
OCR - Operability Concerns Resolution
OI - Operating Instruction ,
OJT - On The Job Training
OP - Operating Procedure
PC' - Precursor Card
PM - Preventive Maintenance
PMRG - Plant Modification Review Group
PMT - Post Maintenance Test
PORV - Power Operated Relief Valve
PR - Problem Report
PRC - Plant Review Committee
PT - Licuid Penetrant Test
RCA - Raciologically Controlled Area
RCBT - Reactor Coolant Bleed Tanks
RCP - Reactor Coolant Pump
REA - Request for Engineering Assistance -
RG - Regulatory Guide >
RP&C - Radiological Protection and Chemistry
SBLOCA - Small Break Loss of Coolant Accident
SEL - Security Event Log i
SIR - Security Information Reports
SLUR - Second Level Undervoltage Relays
SM - Shift Manager
SP - Surveillance Procedure
SR - Surveillance Requirement
SRO - Senior Reactor Operator
SSC - System. Structure or Component
SSOD - Shift Supervisor on Duty
TC - Temporary Change
TDBD - Topical Design Basis Document
TS - Technical Specification
URI - Unresolved Item
VIO - Violation
WI - Work Instructions
WR - Work Request
. WSI - Welding Services. Inc.
,