ML20216E961
| ML20216E961 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 03/04/1998 |
| From: | Johnson T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20216E898 | List: |
| References | |
| 50-302-98-01, 50-302-98-1, NUDOCS 9803180211 | |
| Download: ML20216E961 (76) | |
See also: IR 05000302/1998001
Text
,
I
'l
'I
!
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No: 50-302
License No: DPR-72
Report No: 50-302/98-01
Licensee: Florida Power Corporation
Facility: Crystal River 3 Nuclear Station
Location: 15760 West Power Line Street
Crystal River. FL 34428-6708
Dates: January 4 through February 7. 1998
Inspectors: S. Cahill., Senior Resident Inspector.
T. Cooper Resident Inspector
S. Sanchez, Resident Inspector
P. Fillion. Reactor Inspector. (Sections E8.8 - E8.12)
C. Julian. Technical Assistant. (Section~01.4)
R. Gibbs, Resident Inspector. North Anna. (Section
l .01.4)
K. O'Donohue, Resident Inspector. Vogtle. (Section
01.4)
L. Wert. Senior Resident Inspector. Browns Ferry.
(Section 01.4)
R. Schin. Reactor Inspector. (Sections 08.2. E8.1.
E8.15 - E8.16)
M. Thomas. Reactor Inspector. (Sections E8.2 - E8.5)
,
J. York. Reactor Inspector. (Section 08.1, E8.6 -
L E8.7. E8.13 - E8.14)
F. Wright. Senior Radiation Specialist. (Section R1.1)
Approved by: T. Johnson Acting Chief. Projects Branch 3
{ Division of Reactor Projects
ENCLOSURE 2
9803180211 980304
PDR ADOCK 05000302
G PDR ;,..
!
,
I
l 3
EXECUTIVE SUMMARY
l Crystal River 3 Nuclear Station
l NRC Inspection Report 50-302/98-01
y
i This integrated inspection included aspects of licensee operations
i engineering, maintenance, and plant support. The report covers a 5-week
l period of resident inspection: in addition. it includes the results of
- announced inspections of open restart items and start-up activities by
l regional inspectors.
Operations
Deficiencies were observed with the threshold of operators log entries and
attention to detail and with the administrative control of Operations
equipment tracking and promulgation of guidance processes (Section 01.1).
A Violation (VIO 50-302/98-01-01) was identified for closure of red-tagged
l electrical components. The inspectors had previously concluded that the
licensee clearance tagging process was significantly deficient. Although the
licensee had responded adequately to the details of each problem with
corrective actions the inspectors concluded that a comprehensive corrective
action plan was warranted considering that errors continue to occur (Section
01.2). '
l
The inspectors concluded that Operations was very cautious and deliberate
while performing reactor startup activities. Numerous changes required to
routine Operation's procedures were indicative of a weakness in procedure
issuance and change control and a poor review of procedures prior to a
significant evolution. However, many changes were the result of heightened
scrutiny of problems that had not been challenged in the past (Section 01.3).
l
'
The second phase of an Operational Safety Team Inspection (OSTI) was conducted
at power operation. The team observed that overall command and control of the
operators was excellent, reactivity management was consistently given the
highest priority, and operator performance was generally very good.
Operations' shift supervision aggressively pursued operational and design
issues, and exercised good oversight of control room activities (Section
01.4).
The OSTI team noted that management oversight of the plant startup was
assigned on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shift coverage and focused on independent assessment of
operator conduct. The shift presence by management personnel was effective
end contributed to efficient closure of engineering and operational issues.
Managers participated actively in reactivity management activities and were
actively involved and knowledgeable of emergent issues. The team concluded
management oversight of the power ascension was appropriate (Section 01.4).
The OSTI team noted that operation of the main turbine controls and expected
plant response while placing the main generator in service was observed to be
an operator knowledge area needing improvement. Use of annunciator response
3rocedures and communications by operators during plant events were adequate
)ut inconsistent in formality. Communications between operators and
instrument technicians were also inconsistent (Section 01.4).
!
I-
l
l
r
L
!
l
'
2
The OSTI team observed that the surveillance procedure for verification of
proper reactor coolant system flows required revision because it did not
initially consider the density effects of changing reactor coolant system
temperatures at lower power levels. Numerous other minor 3rocedure
- corrections were required during the startup, indicating tlat procedure
validation had been deficient (Section 01.4).
l
- The OSTI team observed that plant materiel condition had improved and was
acceptable, but improvements can still be made (Section 01.4).
The OSTI team noted that individuals from various plant departments were
conducting independent observations of plant work and startup activities and
had the correct threshold for findings (Section 01.4).
A Violation (50-302/98-01-02) was identified for failure to perform required
postings of documents involving radiological working conditions, proposed
imposition of civil penalties and any response from the license to proposed
imposition of civil penalties (Section 01.4).
The inspectors concluded the licensee's reactor building closeout processes
were very detailed, but several discrepancies were identified by inspectors
that had not been questioned by the licensee. All of the items were resolved
and determined to be of minimal safety significance. However, this was
somewhat fortuitous because the licensee had to expend significant effort
resolving the adequacy of items the inspectors expected to have already been
'
questioned (Section 02.1).
The licensee has identified a number of components not in their expected
position, many due to deficiencies in implementing procefore changes. The
inspectors considered Operations' control and review of cheir procedures and
their role in modification impact screening to be a col'ective weakness
(Section 02.2).
Numerous 3roblems were identified by the licensee in the area of Document
Control. )ut the issues were indicative of new management uncovering
longstanding problems in this area. The problems contributed to an identified
weakness in operations * procedure control and issuance. The inspectors
concluded the licensee's planned actions were appropriate, and good management
oversight was being applied to the area of document control (Section 04.1).
Several observations of operator performance indicated deficiencies in
l Operations' questioning attitude and attention to detail (Section 04.1).
l
A Non-Cited Violation (NCV 50-302/98-01-03) was identified for failure to
,
follow an Operating Procedure for aligning a decay heat system purification
l loop resulting in the lifting of a system relief valve. The licensee
I recognized their corrective actions to a previous probl.em could have been more
aggressive. and they responded thoroughly and promptly to this latest example
(Section 04.2).
3-
The inspectors concluded that the licensee's corrective action system remains
adecuate but weaknesses were observed with the adequacy of Level C precursor '] '
carc evaluations and corrective actions and the timeliness of root cause
evaluations. Poor oversight by the licensee's Nuclear Safety Assessment Team
responsible for the corrective action system contributed to these problems
developing. Both issues were being adequately addressed by licensee
management (Section 07.1).
A Non-Cited Violation (NCV 50-302/98-01-04) was identified in that the
. licensee was over one year late in submitting a required report of Improved
Technical Specification Bases changes (Section 08.2).
A' weakness was noted in the corrective action program in that it was not
always driving the corrective actions, and the corrective actions were not l
always thorough (Section 08.2).
-Maintenance
Engineered Safeguards Actuation System testing observed by the inspectors was
- performed in a deliberate and controlled manner, with no significant concerns
'
noted (Section M1.2),
A local leak rate test (LLRT) on high pressure injection recirculation valves
failed because the licensee discovered a required back pressure s)ecification
f
'
was poorly transmitted or conveyed to the vendor. Consequently tie valves
were not designed to withstand the LLRT back pressure. The inspectors
'
determined that the licensee's corrective actions to modify the valves were
appropriate because the valves passed the test. However, the omission of the
back pressure specification was an example of poor Engineering performance
(Section M1.3).
'
Enaineerina
The licensee was effectively addressing identified problems in their
L modification processes. They were applying more conservative management
l expectations to longstanding inappropriate practices with generic
o modifications and control of temporary configuration changes (Section E1.1).
The licensee's modification process did not support accurate procedure and
plant equipment control changes. Tracking of open items was informal and was
scattered in various programs and had a significant potential for needed '
changes to be omitted. The format of modification return to service packages
was poor and informal, which did not support the performance of detailed and
quality reviews by Operations. The inspectors concluded the licensee *s
' modification return to service and procedure impact screening processes were
weaknesses (Section E1.2).
A Non-cited Violation (NCV 50-302/98-01-05) was identified for failure to
promptly correct the seismic qualification of NuPro valves and for inadequate
corrective actions to ensure all NuPro RL3 relief valves were removed or
prevented from being used in the plant. The inspectors concluded that the
licensee's extent of condition review for a related Precursor Card (PC) was
(
l
!
4
focused too narrowly. In addition, poor Engineering performance was noted
l
regarding prior resolution of the seismic qualification and documentation
problem. This licensee identified issue was thoroughly investigated and was
of low safety significance because the resolution did not change anything in
the plant but merely provided the seismic qualification for existing
components (Section E1.3).
A reportability evaluation on valve erosion concerns from throttling of makeup
pump discharge valves was identified by the inspector as deficient. The
evaluation only addressed emergency aump operations and not normal operation.
This obvious omission was also not clallenged by Operations in their review.
Although it was known by Engineering that no concern existed with the valve
position for either normal or post accident situations, the omission
demonstrated poor documentation of a concern and a lack of questioning
attitude (Section E2.1).
Numerous open items and restart issues were inspected and either closed or
determined acceptable for restart of the unit (Sections E8.1. E8.3 through
F8.15. E8.18. E8.19 and E8.22). Additionally, several Licensee Event Report
issues were found to be adequately resolved and corrected by the licensee and
were identified as further examples of Non-cited Violation NCV 50-302/97-21-
01. Examples of Noncompliance in Design Control. 50.59 Evaluations, Procedure ,
Adequacy. Reportability, and Corrective Actions That Are Subject to '
Enforcement Discretion (Sections E8.17 and E8.24).
The inspector concluded from reviewing operations shift logs that shift
manning was in accordance with the requirements of licensee administrative
instructions Al-500 and AI-2205, and adequate operations personnel were on
shift to meet minimum shift staffing for performing Abnormal Procedure AP-990
and for manning the fire brigade (Section E8.2).
A Violation (VIO 50-302/98-01-06) of Appendix R requirements was identified
for the lack of installed 8-hour battery powered emergency lights in the
control rod drive (CRD) room and in the access pathway to the CRD room for
the abnormal procedure AP-990 operator action of opening the CRD breakers
(Section E8.2).
The inspectors concluded that Abnormal Procedure AP-990 was weak in that it
did not require operators to check rod bottom lights after pushing the reactor
trip button and contained no guidance on use of emergency boration if the
reactor did not shut down (Section E8.2).
A Violation (VIO 50-302/98-01-07) was identified in that the 500 KV backfeed
was not qualified as a source of offsite power whea used in the past (e.g.. in i
March 1996) (Section E8.16). l
A Violation (VIO 50-302/98-01-08) was identified in that adequate procedures
were not in place for use of the 500 KV backfeed during August 1997 through
January 1998 (Section E8.16). I
During review of a justification for continued operation (JCO). establishing l
l emergency diesel generator operability for cooling temperature concerns. the l
l
j
5
NRC identified that several requirements for contingency actions and
administrative controls for ambient temperature monitoring were not yet
implemented. The licensee was processing required procedure revisions but had
not implemented interim controls due to a misconception that the JC0 only
applied in Mode 4 and above. The JC0 was mode independent and applied for all
winter month operation. This was poor implementation of Engineering's
operability contingency requirements (Section E8.20).
The licensee has installed administrative controls and hardware modifications
which adequately address License Condition 2.C(11), as described in License
Amendment 164. The thermocouples had been classified as inoperable based on
acceptance criteria in a draft procedure revision which was a conservative
operations department decision. The dispositioning of the issue by
engineering, which determined th6t the acceptance criteria were not correct,
demonstrated that deficiencies existed during the review of the procedure
revision (Section E8.21).
During review of an open restart issue involving implementing setpoints, the
NRC noted that the licensee had not completed the required procedure changes
following the calculation upgrades and was not tracking the individual
procedures until questioned by an inspector. This was considered poor
tracking of necessary restart restrictions (Section E8.23).
Plant Sucoort
A Non-Cited Violation (NCV 50-302/98-01-09) was identified for failure to
Jerform radiation protection general employee training walk-through in the
Radiation Control Area (Section R1.1).
i
e n x
h d
l i
g
l
e
te o s p
v C e m
ni t m D o
it
c o o e C
ne N t t e
rp s h l
.
s y y t o
es 84 d b S r
ce E2 G A G G r d f t
nr a n l o n
o C a a o
ce 83
.
t s e C
h E2 I A A A r S o d
Ct o p i n
R s t s s i
Nn -
r o i t
i 2 u H D u d
g c O e
8
nd
ie E0 A A A A e
r
m e t
us o
r
t n l
ns P
e
s o u
ie 7 g
f a i s
tr 1 0 W t e
0 a t a R
nd
od
8 0 k n e r
ca
E A A A A 4 a a v e a
y e l i p i
fs L P t O r
oeu 1 l c e
e e e a n t
ss H 8 t p h o i i
as P
E5 G G G G G a o t i r
A m l d d C
ei
r R
i
x
e e a e
G 3 v k R t n
aci A 1 o n a l g
R
r E T l u i
ef 8 p l s s
vi A E G G G G p y o a e e
ic P A t t t R D
fe i s
p T 8 r l s n t l -
es N
E o i e I h a
h
M
8 F b r g c
te E S S S G a u d i i
h S s t d n s r
nt S n i e a r t -
i E 6 o b c e c
o S
S
i a o n v e
et
A
8 t H r g O l
-
6 c E G G G G c P i E
nd
ae A m s g
e o f e n n
mt 3 t
a e o o D i i
ri v R r
om 8
G A A
u
q i ym o e y
fi E e t l co t e c
rl
e
d c o ao n n
pe
a
n e
r
r uR
q
e
r
im
ge
e
t i
r 2
I
r n el u nt c
sa 8 = o o do l Es i
C C Ar
'e s E I I I I A I
- n
t
iR
aA nS
y f
e
et
sn 4
2
- FS A l D
3o F
ne 1 le n 0 0 0C : :a :
em
cs B A A A A bo -
2
- - 3e 0s 0
E ai
tt
1 2e 0h 0 m, 0
is pa 1 0 0h t - -
l e en - - t 6 8 . 3
s cn 7 5 7 1n 3i 4
es 2 co 9n 9 9e i D -
ha .
Af /o / /d 7 7 7
t 8 /n 2i 2 2i 9d 9e 9
e eI
dh
~et
0 A A A A t
at
un
0t
3e
l
0
3
-
0s
3t
- u
/e
2b
0i
/t
2s
0a
/
2
0
-
s qe 0p 0 0O 3r 3W 3
s s ei 5m 5 5 c - -
e: s s n dc
Ai o m 0s 0e 0
ss s i o f IC I Oo 5e 5h 5
sn t e s i
e =f F R I r D t
aoi N
R h n
e B
a t
a c As u I o U Vf O R R
E g v n n T I s Er E
st C i
n
l
u a ) ) ) n Va Lo L
rc N s
r
i
t g g m
r d/
I
dd d dw f
oe O e c i e o od ee e eo ) g ) )
_
ts C v e s R f oe sk s sd nn ns n
_
c O f e r Gt oc o ot ei ei e
_
eg . F f D h e a l a l l u pp ps p
_
pns O E t P = u Cr C Ch
t
n f i l 0i 0a 0
sin A. g o W r Ga v (T ( (S (P (B (
_
nwo
ioi
E
R
e
m i
n
e e o E _
A e r g c t
lt g
e n a r
el c C a
n e
d
e a r ot
e ie -
hoe R a n l i
p rh
Tfs N M
i w l
O e
g o p p-
n n m u : : : : :
E K o Sk 2 1 2 3 6
C n .
a 8 8 8 8
l 8 _
3B 0 E E E E
.
_
_
_
_
_
.
_
.
_
_
_
.
- .
1
7
~ Chiller Motor Trip Set Point Being Set Below Full Load Ampere x
Setting-
E8.8 (Closed) LER 50-302/97-41-00: Control Complex Chiller may be
Rendered Unavailable due to Design Error
E8.13 (Closed) LER 50-302/96-05-01 and LER 50-302/96-05-02: Inadequate ~
Failure Modes Review Creates Possibility of Cooling Water Flow
Outside of Design Limits
(0 pen) VIO 50-302/96-01-06: Failure to Correctly Translate Design
Basis of SW System into Procedures. Drawings, and Instructions
E8.15: (Closed) EA 97-330. VIO B (01023): Failure to Update the FSAR to
Include Added EDG Trips
E8.17: (Closed) LER 50-302/97-45-00: Containment' Isolation Valves Not
Seismically Qualified Due to an Installation Error
E8.20: (0 pen) LER 50-302/97-13-00: Functional Testing of EDG-1A Room
Temperature May Exceed 120 f
(0 pen) LER 50-302/97-19-00 and 50-302/97-19-01: Elevated EDG
Supply Air Tem)erature Due to EDG Radiator Discharge Air
Recirculation Effect
(0 pen) LER 50-302/97-27-00: Failure to Add Antifreeze to the
- Diesel Generator Coolant Radiators May Render EDG. Inoperable
During Subfreezing Temperatures
E8.23 (Closed) IFI 50-302/97-17-05: Resolution of Improved Technical
Specification Setpoint Program Deficiencies Prior to Entry Into
Mode 4
E8.24: (Closed) LER 50-302/97-14-00: Reactor Building Penetrations Do Not
Meet Code Requirements - Outside Design Basis
(Closed) LER 50-302/97-37-00: Containment Integrity Cannot Be
Proven Following Calibration of Building Spray Pressure Switches
.
Report Details
Summary of Plant Status
The unit began the-inspection period in Mode 5 with the reactor coolant system
'(RCS) pressurized to approximately 50 psig by a pressurizer bubble, continuing
-in the outage that began on September 2, 1996, A secondary system condenser
-v3cuum was being maintained using steam from adjacent coal power plants, and
the secondary fluid systems were in long' cycle cleanup. On January 15, 1998,
a makeup and purification system pump (MUP) was started, and makeup to the-
RCS, reactor coolant ~ pump (RCP) seal injection, and normal letdown flow were
established. On January 20, 1998, two RCPs were started commencing hest up of
the RCS. Mode 4.(RCS temperature > 200 degrees F).was entered on January 21,
1998, and the decay heat removal system was secured. Un January 25, 1998, a
third RCP was started and Mode 3 (RCS temperature > 280 degrees F) was
entered. -On January 27, 1998, the fourth RCP was started, the reactor
protective system and engineered safeguards high pressure' injection (HPI) were
enabled, and normal RCS operating temperature and pressure were attained. On
February 1-,1998, a reactor startu) was initiated and Mode 2 entered. Mode 1
(reactor power > 5%) was entered s1ortly thereafter on February 2, 1998. On
February 5, 1998, the generator output breakers were closed and power
increased to 25%. .The output breakers were opened later the same day for
planned turbine over speed testing and balancing. On February 6, 1998, the
output breakers were closed and the unit ) laced on line, Power was-raised to
48% by the end of the report period on Fe)ruary 7,1998.
I. Operations
01 Conduct of Operations
01.1 . General Comments (71707 and 71715)
Using Inspection Procedures 71707 and 71715, the inspectors performed
routine reviews of plant operations' which included Mode changes, reactor
startup, ' shift turnovers.- response to emergent problems,1og reviews,
coordination meetings, and restart activities.
_
l Significant observations
!
are discussed in subsequent paragraphs.. Several minor observations that
were indicative of deficiencies in Operation's administrative program
performance'are discussed below.
, The inspectors observed examples that indicated the licensee's threshold
L for logging activities was still inconsistent. One example was the
E
failure to log an incorrectly performed closed cycle cooling water pump
swap because the operator errors were delineated on a precursor card
i entered in the corrective action system and an Operations internal
l investigation. A second example involved an unexpected trip of a
L control complex chiller trip auring a surveillance run on January 30,
L 1998. The administrative entry into the Limiting Condition for
Operation (LCO) for the surveillance was logged for the chiller being
inoperable, but available, during the perfrrmance of the test. However,
after the unexpected trip, no log entries were made to document either
the trip or that the chiller was no longer available. Licensee
>
l
2
management considered these examples unacceptable and was taking
appropriate actions. Significant improvement was seen by the inspectors
later in the report period.
The inspectors periodically audited the Control Complex Notebooks in the
control room which contained administrative items and short term
guidance. The ins)ectors observed that numerous Operator Study Book
(0SB) entries had )een-made in a thort period of time. After
questioning some o)erators on a specific OSB entry for newly installed
thermocouples on t1e decay heat drop line and the auxiliary pressurizer
spray line, the inspector concluded the information was not well
retained by operators. Discussions with licensee management revealed
that they had made the observation that the number and complexity of the
OSB entries had resulted in problems with the operations personnel
retaining the information. The inspector also identified a new OSB
entry that had been entered the previous day but was incorrectly filed
in the back of the OSB section. Although correctly entered in the
index, operators did not notice OSB absence and it was not reviewed by
the two shifts of operators who performed shift turnover after it was
entered. The inspector reviewed the temporary modification (TMAR) log
and observed that, although three were listed as active in the index,
pacerwork for five TMARs was in the binder. The paperwork for two l
recently canceled TMARs had not been removed when deleted from the
index. The ins)ector reviewed the Short Term Instructions (STI) and
verified that t1ey were appropriate but noted that the index had not i
been audited or consolidated since April of 1997. A tab in the book for
the modification tag index had a note stating it was removed to the Work
Control Center, but an outdated status report dated July 1. 1997 was
filed behind the tab. The inspectors noted other deficiencies such as
incorrect dates throughout the notebooks. The inspectors concluded that
the Operations short term guidance content was appropriate, but that 1
administrative control of Operations p ucesses and attention to detail
was deficient. )
On February 7, 1998 at 8:00 p.m., a conference phone call was held to
review the licensee's progress towards the 50% power plateau. The call
was held between the licensee and NRC Region 11 management including the
acting Regional Administrator, the Director of the Division of Reactor
Safety, the Division of Reactor Projects Branch Chief, and the Senior
Resident Inspector. Encountered operational challenges and preparations
for further power ascension were discussed. The NRC staff did not
identify any significant concerns and considered the licensee was
adequately prepared to progress through the 50% plateau. ;
01.2 Clearance Taccina Problems
! a. Insoection Scooe (71707)
The inspectors reviewed the licensee's corrective actions in response to l
three previously reported issues and their associated precursor cards
(PC):
, l
!
l
i
I
3
e man 5ulation of a red tagged breaker handle (PC 97-8458/ Level B),
e inadvertent positioning of a red tagged breaker while performing
wiring checks necessitating opening of the breaker cabinet door
(PC 97-8500/ Level B), and ;
1
e closure of red tagged links by contract electri:ians (PC 97- I
8720/ Level A)
b. Observations and Findinos l
The investigation and corrective action plans for the first two issues ;
were reviewed and approved by the licensee's Corrective Action Review i
Board (CARB) on January 29, 1998. The inspector reviewed the
documentation anc observed the discussions between the investigators and
the CARB. Both of the issues contained unique circumstances that l
resulted in minimal impact on personnel or plant safety. On the first i
issue, although the individual manipulated a breaker handle with a red l
tag on it, it was definitively known by the individual that the breaker I
was removed from its cubicle and the handle remaining on the cabinet was
not connected to any electrical components. The individual had
performed the manipulation to demonstrate to an inspector that although !
the handle had spring-returned to the ~0N" position when the breaker was
removed, contrary to the red tag position of ~0FF", it's position was
inconsequential since it was disconnected. This example was further
discussed in NRC Inspection Report (IR) 50-302/97-20. The second issue
involved the aligning of the red tagged breaker handle to open the
breaker cabinet door. The handle was not repositioned from its tagged
position and was never intended to be. However, it had to be moved very
slightly to allow clearance to open the door. In both cases the
inspector was concerned that the principle of not operating red tagged i
components was not understood and implemented. The licensee's '
corrective actions effectively addressed this concern, noting changes in
clearance training that had already been implemented. The licensee
determined the involved individuals understood the implications of their '
actions. The inspector considered the licensee's response to these two
issues adequate to resolve the concerns. !
The third issue involved closure of linkages TB60-1 and TB60-2 in an l
l
electrical panel that were clearly red tagged. The linkages fed an l
l
indication circuit undergoing modifications and were red tagged in the
" link open" position by tag numbers R-009 and R-010, respectively. of ;
electronic clear :.nce order number 97-12-157. Although, the two contract I
electricians and a third contract individual claimed the red tags were
not present when they closed the links at approximately 11:30 p.m. on
December 21. 1997. the licensee's investigation did not support their I
claims. The licensee discovered the problem when the next shift of
electricians observed the links closed with the tags hanging on the
links at approximately 6:00 a.m. on December 22, 1997. The licensee
determined the tags had been hung and verified the previous day and had 3
not been moved er altered since. The licensee's Compliance Procedure i
(CP) 115. Nuclear Plant Tags and Tagging Orders, Revision 76. Section {
>
E
L
p
u
o 4
3.2.1. requires that red tagged components are not to be repositioned in
any way.
,
The licensee took prompt and comprehensive corrective action when the
aroblem was discovered. This included suspending the involved System
iaintenance Crew (SMC) contractor's switching and tagging
qualifications, a re-validation of all open modification-related
clearances to ensure no other components were out of position, and
expeditious removal of all non-essential SMC personnel from site. Since
!
the licensee was aware of several performance errors involving SMC
l contractors and 3roblems with clearance tagging, the licensee elected-to
l- assign the PC a _evel A designation and perform a common cause analysis.
L
'
The inspector recognized that much work had.been done by the licensee in
1997 on Compliance Procedure CP-115 to address clearance errors as
documented in previous. reports. These errors have generally lessened in
,
severity and type throughout the year and the rate has gone down notably
l as a result. However., errors continue to occur and challenges exist
with the procedure, contractor control (SMC), and switching and tagging
training. The first example above also involved an SMC electrician.
The licensee had not completed the Level A PC common cause analysis at
the end of the report period, but their preliminary assessment pointed-
out deficiencies in each of these areas necassitating a significant and
c comprehensive revision to the process was wa ranted. Tho licensee Was
! planning a complete revision to their clearance tagging program and
l required training to address the ongoing prob' ems. ITS 5.6.1.1 and NRC l
l Regulatory Guide.1.33. Revision 2. require procedures for tagging and
, control of plant equipment. The closure of the clearly red-tagged links
l contrary to CP-115 requirements is being identified as Violation (VIO)
50-302/98-01-01. Closure of Electrical Linkages While Under a Red Tag
Clearance,
l
C. Conclusions i
l The inspectors have previously concluded that the licensee clearance
!- tagging process was significantly deficient. Although the licensee had
L . responded to the details of each problem with corrective actions ~ the ,
. inspectors concluded that a comprehensive corrective action plan was !
, warranted considering that errors continue to occur. A violation was .
E
identified for closure of red-tagged electrical components. The !
inspector concluded these and other examples indicate that the
,
licensee's overall process for configuration and status control of plant
l- equipment was deficient.
01 3 Plant Startuo. Mode Chanae. and Power Ascension Control
a. Insoection Scooe (71707 and 71715)
The inspectors reviewed the licensee's plant restart and power ascension
activities as' generally defined by Administrative Instruction (Ai)-256.
Station Readiness for Restart Sequence Reactor Restart and Power
!- Ascension Plan, Revision 2. The inspector's activities included
{ !
\
l
-___
5
observing the conduct of hold point meetings, review of the Restart Mode
. Restraint list, performance and tracking of mode change surveillances,
and augmented shift observations of significant plant evolutions such as
reactor startup and Technical Specification (TS) mode changes.
b. Observations and Findinos
The inspectors observed that an inordinate number of Immediate L'orking
Copy Changes (IWCC) had to be made to Operations procedures in order to
complete them. Particularly noteworthy were the numerous IWCCs to
Operating Procedure (0P)-502. Control Rod Drive System, and OP-210.
Reactor Startup. Several problems were encountered with procedure
sequencing when withdrawing safety rod groups in OP-502 on February 1.
1998. After several IWCCs the Nuclear Shift Manager (NSM) suspended the
reactor.startup process and directed that a review of the procedure and
simulator validation be done and a formal revision issued to correct all
problems. Many of these problems could have been corrected if a
thorough review of the procedure had been done or the operator's
simulator startup training had used initial conditions other than all
safety rods already withdrawn. Additionally, several steps in OP-210
and OP-203. Plant Startup, were confusino to the operators and had to be
clarified by management as to the intent.
The inspectors were also concerned as to why numerous problems were
encountered with these procedures relative to previous reactor startups
considering little modification was done in these areas during this
outage. The inspectors observed another example involving a change to a
control rod drop Surveillance Procedure'(SP) to provide credit for
another rod exercise SP that had previously been credited by the
)erformance of an unrelated Periodic Test (PT). The change was needed
)ecause the licensee had raised expectations to ensure surveillances
were done by an SP and the original rod exercise SP could not be
performed when attempted due to overly restrictive plant condition
limits. .These examples were considered to be poor control and
accomplishment of surveillance requirements. The inspectors considered
these problems part of an overall weakness with Operations )rocedure i
issuance and change control. Operations investigation of t1e problems
,as documented in various PCS revealed that some administrative changes
had unintentionally altered the flow or wording of the procedure such
that the operators were not familiar with the change intent. The i
licensee also concluded that operators were implementing heightened i
management expectations and were questioning minor procedure
inadequacies that they had not challenged in the past. The inspector's ;
observations were consistent with this conclusion. l
!
The inspectors observed that the licensee controlled the reactor startup
per Al-550. Infrequently Performed Tests or Evolutions. Management
oversight was thorough and reinforced ex)ectations, particularly at pre-
job crew briefings. Operators were deli)erate and cautious throughout
the startup. They dis) layed a very conservative questioning attitude
which contributed to tie identification of the procedural problems s
} discussed above. The operators demonstrated good communications, with !
,
____m______m____
6
constant re) eat back of information, and the control room Senior Reactor
Operator (SRO) maintained constant awareness and oversight of ongoing
[ evolutions. The inspectors reviewed the Estimated Critical Position
(ECP) calculation performed for the reactor startup. The inspectors
noted that the licensee had the calculation performed by one operator
l and then verified by a second as required. but they also performed a
third verification. The inspectors noted on the startup that the ECP
corresponded well with the actual critical rod position.
The inspectors did not identify any problems with the Restart Mode
Restraint List or recuired AI-256 reviews and oversight. However, the
inspectors considerec tracking of mode change surveillances challenging.
The licensee's overall surveillance tracking process contained in
Procedure SP-440. Unit Startup Surveillance Plan, was not linked or
referenced in OP-210 or OP-203 which ware the procedures controlling and
directing plant condition changes. This required the NSM to refer to
procedure SP-440 to determire which SPs were needed at any given point
in the startup. However, several of the activities sequenced by SP-440
required specific plant conditions such as an average RCS temperature
that were not explicitly directed by SP-440 or OP-210. The NSM's
knowledge of the applicable alant conditions required for the SP were
the only barrier to ensure t1e SP was done before exceeding the correct
plant condition. However, the inspector did not identify any missed SPs
and concluded the coord' nation of SPs in the ops would be an
enhancement. ,
c. Conclusions '
The inspectors concluded that Operations was very cautious and l
deliberate while performing reactor startup activities. Numerous
changes required to routine Operation's procedures were indicative of a
weakness in procedure issuance and change control and a poor review of
procedures prior to a significant evolution. However, many changes were
the result of heightened scrutiny of problems that had not been
challenged in the past.
01.4 Doerational Safety Te6m Insoection
I
a. Inspection Scope (93802) I
'
The first phase of the Operational Safety Team Inspection (OSTI) to
determine tne readiness for restart of the Crystal River plant was
conducted in December 1997 and documented in IR 50-302/97-20. The
second phase of OSTI was conducted by a subset of the same inspectors
during the period February 3-6, 1998. The inspection was performed by
an NRC Team Leader, a Senior Resident Inspector and two Resident
Inspectors. During the period the reactor was critical and operating at
varying power levels between 5 and 25% of full aower level and tne
operating staff was in the prov ss of placing t1e turbine generator on
line and testing all its protective functions. The inspection focused
on the conduct of plant operations and consisted of over 50 heirs of
I continuous
_
_. - __ _ ____ _ __ _-_______
7
observation of the conduct of operations by the inspectors in tFe
control room and other plant locations.
b. Observations ~and Findinas
Doerations Command And Control-
Overall command and control was noted to be strong. The Nuclear Shift
Managers consistently were effective in their control of important
activities. . Technical Specification action statements were initiated
promptly and conservatively. The shift managers aggressively pursued
operability issues such as a service water pump material question and
engineering design issues. Reactivity management was consistently given
the highest priority. The control room operators continued to be highly
professional in their duties. The control room was maintained
consistently quiet and free of unnecessary personnel. The team observed
that procedures were readily available and current in the control room.
The team verified that the control room copy of the emergency operating
procedures were the latest approved revisions.
Shift senior reactor operators were well prepared for shift turnover
briefings. The inspectors observed that shift turnovers were delayed
when the need arose. Additionally, during a balance-of-plant reactor
operator relief in the middle of a shift the shift SR0 was observed
repeating the details from the earlier shift briefing. Ensuring all ;
information was addressed during mid-shift turnovers was a good '
practice. I
Because the work control program was not fully implemented a.large
portion of the maintenance activities were controlled from the control ,
room by shift management. This resulted at times in heavier than i
desirable control room traffic. The shift SRO was observed taking
action to ensure the additional activities did not distract the control
board operators.
'Manaaement Oversicht
During the period of plant startup licensee managers were assigned ~ to
the. control room area 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day to ensure that proper safety
focus was maintained. The inspectors discussed the role of the
ove: sight-responsibility with several of the managers. The inspectors
found that independent assessment of operator conduct.was one of the key .
focal points. Specifically, issues such as response to annunciators,
'
)
l- procedure use, communications. and operator professionalism were areas .
obh./ed. Engineering issues were addressed immediately and operability ;
issues were pursued aggressively, both of which contributed to well i
controlled plant operations. The managers also participated actively in
, reactivity management achvities such as direct observation of control
rod manipulations and reactor coolut dilutions for reactivity control.
The inspectors found that the managers were actively involved and
knowledgeable of the issues. Management's oversight of the power
ascension was appropriate.
- _ _ _ _ - _ -
_- _ _ _ _ _ _ _
8
.The overall plant restart was directed by procedure AI-256. Station
Readiness for Restart Sequence. Reactor Restart and Power Ascension
Plan. Revision 2. dated 12/8/97. The inspectors reviewed the
documentation of the completed portion of procedure AI-256 to date and
concluded the documentation was complete and of good quality. The
inspectors noted that individuals from the various plant departments
conducting independent observations of plant work had the correct
threshold for findings.
Operator Performance
Control room reactor operators were appropriately attentive during the
shift activities. They were well informed and knowledgeable of the
current plant conditions. Although there was some inconsistency with
the use of the annunciator response procedures, generally, the control
room operators were well informed of the cause and significance of lit
annunciators. Reactor operators' responses to alarming annunciators
were usually correct, but sometimes inconsistent in that although the
alarms were called out when acknowledged, some repeat backs were missed.
The team consistently observed good .self checking and use of peer in)ut
by the control room operators during operation of plant equipment. T1e
team observed that the operators stressed procedural compliance. There
was a large numter of procedural revisions required, some apparently
necessitated by seaknesses during procedure development or revision.
However, the team noted that the operators stopped evolutions when ,
3rocedure problems were identified and achieved procedure corrections
)efore continuing the activities. q
Licensee management stressed clear communications in the conduct of
operations and most plant personnel communicated clearly. However. ;
during nuclear instrumentation gain adjustments. the team observed that !
communications between the reactor operators and the technicians were
inconsistent. They did not consistently utilize the phonetic alphabet
or provide good repeat backs.
On February 4.1998, during a walkdown of the control room panels the
inspectors observed two chart recorders that were not inking properly.
An operator responded to the inspectors * questions and corrected the ,
problems. The recorder chart paper had becn initialed and dated once l
per day by an o)erator tasked to check for proper operation which i
included a checc for proper inking. One of the recorders had not inked i
for several days. The inspectors discussed this deficiency with the
Nuclear Shift Manager who took immediate action to correct the problem.
PC 3-C98-0813 was also initiated.
On February 4. 1998', portions of the performance of Procedure OP-203.
Plant Startup. Revision 81. were observed. Section 4.3. Turbine
Generator Startup, provided instruction for locally resetting the
turbine. The plant operators attempted to reset using step 4.3.6. The
turbine did not reset. Although Operations personnel seemed to be {
unfamiliar with the turbine control system, after researching the issue
_ _ - _ _ -
9
-the licensee determined that the step 4.3.6 substeps were in the wrong
sequence. Apparently, during the review process. the procedure was not
thoroughly validated for all plant conditions.
Operations personnel developed an immediate working copy change per
Procedure AI-400C. New Procedures and Procedure Change Processes.
Revision 23. They were completely. familiar with the procedure revision
process. The turbine was reset successfully using the immediate working
copy change.
Later in the turbine startu), while the turbine was in process of being
rolled to 1800 rpm, the tur)ine valves response appeared erratic. Under
the direction of the Control Room SRO. the turbine was manually tripped.
Operations personnel entered Abnormal Response Procedure (AP)-660.
Turbine Trip, Revision 11. and performed all of the steps appropriately.
Ooerator Knowledae
The inspectors discussed operation of the emergency feedwater (EFW)
system with a Plant 0)erator. Items discussed included normal system
-lineup, operation of t1e governor and trip and throttle valves efforts
to reduce condensate in the steam supply piping. miscellaneous
instruments used for system testing, system flow rate, and items to~
check during routine rounds. The operator's system knowledge was good.
On numerous occasions. the inspectors discussed lit annunciators with
Reactor Operators (R0s) to determine the operators' familiarity with
annunciated conditions. No problems were found.
The inspectors discussed alternate methods to determine reactor power
i with several R0s. The 3rimary method used by the R0s was to divide the
l core delta tem)erature )y 0.44. The inspectors asked the basis of the
0.44 value. 'T1e R0s stated that at 100 percent power the total core
delta temperature between the hot and cold legs was 44 degrees F. The
L R0s Memonstrated this method and compared the result to the calculated
power level from the calorimetric calculation. The estimated power
lcvel using this-method was reasonably accurate. The inspectors also
discussed other means to determine power level including the use of
turbine bypass valve (TBV) position. One of the R0s stated that use of
TBV position was not used at Crystal River which was-later confirmed by
discussions with licensee management. The inspectors stated that some
facilities used this method as an indicator.of reactor. power when
operating at low power levels, as Crystal River was doing. The licensee
initiated Request for Engineering Assistance (REA) 980155 to evaluate
the possibility of providing a TBV position versus reactor power curve
as an alternate means to determine reactor power.
Nuclear Instrumentation Gain Ad.iustments (62707)
On February 3 and 5, 1998. the inspectors observed instrument and
control (I&C) technicians ')erform gain adjustments on the power range
nuclear instruments using )rocedure SP-113G Power Range Instrumentation
10
Gain Adjustment. Revision 2. The adjustments were deemed necessary
because it was reccgnized that uncertainties existed with the
calorimetric power calculation at low power levels (i.e. less than 48
percent power). The inspectors found that the technicians properly
followed their procedure and used good self-checking techniques.
Communications among the technicians were good. Communications between
the technicians and the reactor operators, however, were inconsistent in
clarity. There was proper verification by the procedure reader when
test leads were connected. The inspectors examined the instruments used
for 3 roper calibration and observed that they appeared to be properly
cali) rated. The inspectors also independently verified several voltage
readings and ensured the readings met the acceptance range of the
procedure and no problems were found. Gain adjustments performed on the
power range nuclear instruments during the power ascension were properly
performed. Communications between I&C technicians and R0s could be
improved during maintenance activities.
Unit Synchronization / Manual Turbine Trio Due to Low Steam Heade,r
Pressure
On February 4. 1998, the inspectors observed operators synchronize the
main generator to the grid after an extended plant .nutdown. Prior to
the evolution, the operating crew discussed a)pilcable procedure steps
and pointed out associated controls and switcles. During the evolution.
3rocedures were carefully followed. Self-checking technicues displayed
)y o)erators were deliberate. Commu-ications prior to anc during the
sync 1ronization were formal. The i .pectors noted, however, that
annunciator response procedures were not consistently used.
Specifically, in response to annunciation of an off normal reactor
coolant pump seal flow condition, the annunciator procedures were not {
consulted appropriately. !
l
i Shortly after the main generator output breaker was closed, the Nuclear
!
Shift Supervisor (NSS) directed the R0 to manually trip the main
l
'
turbine. The trip was performed because steam header pressure had
decreased to about 740 psig from a normal operating pressure of about .
900 psig. It was determined that header pressure suddenly decreased due i
! to operator error. The turbine RO observed header pressure to .aitially {
decrease shortly after the generator output breaker was closed. The R0 l
adjusted the turbine controls to increase turbine load too rapidly. '
This action resulted in a sudden increase in steam demand, causing the
l turbine gove'nor valves to open further, causing the low header pressure
I condition. The operator error indicated to the inspectors that
familiarity with turbine controls and expected plant response for
) lacing the main generator in service was an area where operator
(nowledge could be improved.
The operating crew ( ckly entered the turbine trip procedure and took
appropriate recovery actions. During the event, a main steam line high
radiation alarm annunciated and remained sealed in due to apparent
radioactivity in the steam line from the ~B~ steam generator. The
activity was also measured by the condenser vacuum pump exhaust
11
radiation monitor which also. increased it's count rate and peaked at
about 100 counts per minute. The Nitrogen-16 main steam radiation
l monitor, which is designed to detect radioactivity from primary to
! secondary leakage in the steam generator, peaked at a count rate that
l would correspond to a primary to secondary leakage of about 100 gallons
per day (gpd). Radiation monitor count rates decreased following the
l turbine trip. The leakage from the "B" steam generator was below the TS-
i limits of 150 gpd and was verified'by the inspectors to significantly
l decrease by the following day. Proper actions were taken by the
! licensee to respond to the radiation alarms, including radiological
! surveys and sam) ling by the health physics group. It was noted.
! however, that t1e annunciator response procedure for the high radiation
l condition was not used by operators in a timely manner. During the
l event. the inspectors observed that formal communications between the
i R0s and the NSS declined and were not crisp. The inspectors discussed
with the licensee the importance of effective communications and
annunciator procedure usage, particularly during transient events. A
i
precursor card was initiated to evaluate appropriate corrective actions
for the manual turbine trip.
After the plant was stabilized, one of the R0s observed during a routine
surveillance that computer indicated reactor coolant flow was less than
the surveillance )rocedure acceptance value required flowrate with four
i RCPs operating. Juring the outage. the surveillance procedure
acceptance criteria had been conservatively raised to account for
possible instrument measurement error. The plant was operating at a
- power level around 15% power where RCS average temperature increases
'
sharply with increasing reactor power. The licensee believed that the
apparent decrease 1: RCS measured flow was caused by reducing RCS water
- density with increasing RCS average temperature. A TS action statement
was entered and reactor power was lowered to reduce RCS temperature and
'
! the indicated RCS flow increased above the surveillance acceptance
,
value. The inspectors verified that the associated TS were satisfied.
It was later detemined by engineering that the flow acceptance value
found in the surveulance procedure had not been density adjusted to
account for increasmg reactor coolant temperatures at lower power
levels. Subsequently.. the procedure was revised to include an operating
curve which accounted for various temperature values encountered during
low power conditions. On February 5, 1998, the inspectors again
verified that the indicated reactor coolant system flow was within the
required range. The licensee initiated a precursor card to address the
cause of this issue. Proper actions were taken by the licensee once the
l flow condition was understood.
Reactivity Manaaement
The team observed that all the control room operators were sensitive to
maintaining the appropriate focus on reactivity management. At least
one board operator remained fully dedicated to monitoring of reactor
power and control rod manipulation during reactor )ower changes. All I
reactivity changes were closely supervised by an S10. During the
changes the inspectors observed that the R0s took deliberate actions and
I
l
12
closely monitored nuclear instrumentation. Further, the inspectors
noted that the NSS was in the immediate vicinity of the control board
area where the reactivity changes were performed. The NSS provided
appropriate management oversight during the reactivity changes.
Communications between the R0 and the NSS were strong. In ) articular,
the inspectors observed that the R0s announced to the NSS t1e start and
completion when control rods were manipulated.
Plant Housekeepina
The inspectors toured portions of the Auxiliary and Intermediate
Buildings with an auxiliary operator (AO). There was a noted
improvement in housekeeping conditions in these areas as compared to
conditions observed in December 1997 during phase one of the OSTI. In
particular, the inspectors noted that the emergency feedwater pump area
was freshly painted and well lit. The decay heat pits were also toured.
Conditions in these areas were adequate. There was some standing water
on the floor and lighting was somewhat dim. The team concluded that
plant material condition was improved: however, there were still areas
where further improvements could be made.
Reauired Document Postinas
During an initial plant tour on February 3, 1998, the team noted that
the licensee had not posted three NRC Notices of Violation relating to
radiation working conditions issued by the NRC on January 16. 1997, on
the multiple bulletin boards containing other 10 CFR 19 postings.
Additionally, two Notices of Violation from previous years which
involved proposed civil penalties were posted. but the lice.1see's
.
responses were not. The team questioned the licensee's compliance
l personnel on the observations. After reviewing the issues the licensee
acknowledged that the postings were out of date and incomplete and took
prompt action to correct them the next day. Licensee representatives
stated that clear procedures were not in place establishing
responsibilities to maintain the postings current and procedures were
revised to correct the problem.
l
c. Conclusions
The team observed that Operations command and control of plant l
activities was excellent. Shift presence by management personnel was {
effective in that it contributed to efficient closure of engineering and
operational issues. Operator performance was generally very good.
Operation of the main turbine controls and expected plant response while
) lacing the main generator in service was observed to be an operator
(nowledge area needing improvement. Use of annunciator response
procedures and communications by operators during plant events were
adequate but inconsistent. The surveillance procedure for verification I
of proper reactor coolant system flows required revision because it did
not initially consider the density effects of changing reactor coolant
system temperatures at lower power levels. Numerous minor procedure
corrections were required during the startup. indicating that procedure
1
,
i.
i
i
13
validation had been inadequate.. Reactivity management was'well
controlled. Plant materiel. condition was acceptable but improvements
could still be made. The inspectors concluded operator performance was
acceptable to_close the Operator Performance item on the Restart List.
This was FPC restart item issue 0-6.
10 CFR 19.11-requires'that licensees shall post documents for notice to
workers of any notice of violation involving radiological working
conditions, proposed imposition of civil penalties and any response from
the license to proposed imposition of civil penalties. The failure to
accom)11sh the required postings as described above is a violation and
wi_ll ae-tracked as VIO 50-302/98-01-02: Failure to Post Documents as
Required by 10 CFR 19.11.
02 Operational Status of Facilities and Equipment
02.1 ' Reactor Buildina Closeout
a. Inspection Scope (71707)
On January 20, 1998, the inspectors toured the reactor building
containment after the licensee had completed virtually all of their
closeout inspections.
b. Observations and Findinas
The inspectors identified 14 potential discrepancies for the licensee to
resolve. One of these 14 contained several examples of items such as
labels and placards that could be transported to the reactor building
(RB) sump, clogging the screens. The. licensee either removed the
suspect items or verified they were analyzed for sump operability
impact. The licensee resolved the other discrepancies and most did not
require.any action.
However, the licensee went through significant effort and research to
resolve one item. The inspectors had questioned whether the tygon
tubing used for reduced reactor level indication was qualified and
analyzed to be left in containment during operation. The licensee
generated PCs 98-0416 and 98-0424 on the issue and initially determined
that the tygon placed them potentially outside their design basis'
because it was nct rated for above 200 degrees F. After further
research, the licensee determined the tubing should have been adequate
because it was installed under a )ermanent 1979 modification and
.
specified a "Bev-a-Line B-VHT" tu)ing material be used which was
acceptable for use in the RB. However, they identified that the
material had been replaced under a work request contrary to the
modification design requirements, with lower grade tygon tubing without
analyzing.it for the RB atmosphere. After obtaining vendor information
and performing testing the licensee succeeded in analyzing the tygon
tubing for acceptability in the RB, The licensee's Level C PC 98-0424
identified the unauthorized replacement of the tubing under the work
request as an inappropriate action but Jid not identify any corrective
-
14
actions to address it. The PC resolved the immediate issue of analyzing
and-resolving the design implications of the tygon use and did not
address the underlying cause of the problem. The inspector and licensee
considered this as weak corrective action plan and the licensee
initiated another PC to address the corrective action error.
Other observations the inspectors noted involved Health Physics (HP)
radiation postings and control of high radiation area doors. The
inspectors noted that the postings were required to be removed at Mode 4
to 3 transition, but the HP group did not track or log how many postings
were in the RB to ensure all were removed. Removal was based on HP
technicians familiarity with what was posted. The inspectors considered
it possible that something could get missed this way. Another
discrepancy involved an open door to the Makeup and Purification heat
exchanger (MUHE) IC room which had paint peeling on walls. The door had
been modified to add a fine mesh screen and rubber seals to ensure the
paint chips did not get transported to the RB sump. The inspectors
questioned what closed the door and whether the door was required to be
closed. The licensee determined the door was'still controlled as a high
radiation area door and would be closed prior to entering Mode 2. The
inspector questioned whether this was adequate for Modes 4 and 3 when a
loss of coolant accident was considered a potential design basis
accident and the door would need to function to block the paint chips.
The licensee determined that the door was modified under Modification
Approval Record (MAR) 90-05-13-01A and was not credited with any
accident mitigation function and was not safety-related. Therefore, the
door was not needed in any Modes but the inspector considered the issue
poor control of a 3erceived design enhancement. The licensee initiated
a change to their RB closeout procedure to close the door prior to
Mode 4. This resolved the inspector's concern.
The inspectors reviewed the licensee's RB closure procedures which
included Procedures AI-1305. Administrative Inspection of Reactor
Containment, and SP-324. Containment Inspection. Procedure AI-1305 had
been completed at the time of the inspector's RB walkdown and procedure
SP-324 had only a few minor items left to resolve before being
completed. Most of the items the inspectors identified were not
captured by the licensee's process or on their closeout deficiency list.
The inspectors noted that AI-1305 was very extensive in that it assigned
specific zones of the RB to senior licensee management and delineated
numerous expectations for the status of each of those zones. The ,
inspector considered this process a positive enhancement in the {
licensee's closure process and noted that the management tours were
critical and identified many items to be resolved. However, the ;
inspector noted some inconsistencies between Procedures AI-1305 and SP-
'
,
324 as to what material was acceptable to be stored in the RB during l
L power operations and observed that the final responsibility for
dispositioning items for acceptability was not clearly delineated
between Procedures SP-324 or Al-1305. However, the inspector observed 1
that the licensee maintained a detailed iist of discrepancies and did
not certify the RB for closure until the list was cleared. j
l I
L i
L
w-_- .
.. .. .. . . .
. I
15
c. Conclusions
The inspectors concluded the licensee's reactor building closeout
3rocesses were very detailed, but several-discrepancies were identified
)y inspectors that had not been questioned by the licensee. Although-
all of the items were resolved and were relatively insignificant, this
was somewhat fortuitous. The licensee had to extend significant effort
resolving the adequacy of' items the inspectors expected to have already
been questioned
02.2 Comoonent Miscositionina
a. Insoection Scooe (92901)
The inspector reviewed the licensee's review and corrective actions for
.several precursor cards (PC) written for components found out of
position.
b. Observations and Findincs
During the inspection period, the licensee identified five valid PCs
written to document out of position components.
PC 98-0222 was issue'd on January 13. 1998 to address discrepancies 1
identified during the performance of Procedure 0. -700C.120/240/480 Volt i
AC Distribution Panel., During the performance of Procedure OP-700C
between January 7, 1998 and January 12, 1998, the licensee identified a
number of discrepancies with various breaker Jositions. The licensee's
investigation revealed that the majority of tie mis 90si
were power supplies in the mechanical maintenancewhich shop,tioned
powend breakers q
several large power tools. The shop intentionally opened these breaiers
when the equipment was not in use, as a safety precaution. Further
investigation revealed that the breaker for AHF-28A fan (A EGDG Control
Room Ventilation Fan) was found open, when it should have been closed.
The licensee investigated and found that no work had been performed on l
this component. since 1991. The licensee speculated that the breaker
had been opened during modifications in the EGDG room and had not been
reclosed.
On January 10, 1998. PC 98-0226 was issued to document that LRV-131 was
found open, but capped, during the performance of-procedure SP-381.
Locked Valve List. Procedure SP-381 requires LRV-131 to be closed and
sealed. The last manipulation of the valve was during the performance
of SP-179B, Containment Leakage Test in November of 1997. The licensee
identified that SP-179B is written in such a way that one initial
~ indicates the completion of several steps., instead of individual
initials for each step.
On January 10, 1998 PC 98-0282 was written after the licensee identified
that SWV-584. Nitrogen addition valve to service water surge tank (SWT-
1), was found open, versus a normally closed position. Initial
investigation by the licensee identified that the operator performing
16
manipulations of the valve, to add nitrogen to the tank, did not have
the procedure in hand (nor was it required to be), the o)erator was
performing multiple evolutions in a short time period. tie operator was
performing multiple tasks, in addition to adding nitrogen, and the
operator was receiving work instructions from multiple sources.
On January. 18, 1998. nitrogen valve NGV-204 was found closed, while the
licensee was investigating . low water level in the B DC Surge Tank. The
licensee has not been able to identify a definite manipulation that
could have resulted in this valve being mispositioned.
On January 10. 1998 PC 98-0180 was written to document that during.
performance of SP-456. Refueling Interval Equipment Response to an ESAS
Test Signal, valve WDV-4 was closed. The licensee identified that
during the performance of the procedure, the valve is tripped closed,
but the procedure does not reopen the valve during restoration. It was
found during' a normal Operation Procedure Lineup.
Following discovery. the licensee restored all of the, components to the
correct position. These and other issues involving discrepancies-
between SP-381, Locked and Sealed Valve Checklist, and Operations
Procedures, were combined into a single root cause analysis and
corrective action plan by the iicensee. Although.not finalized at the
[ end of this inspection period, the analysis identified weak verification
- and validation, inadequate review of field change notices (FCN) to
l modifications, and 3reviously existing procedure )roblems as potential
l
causes. Numerous.slort term corrective actions lad been com)leted and
the. licensee expanded the scope of their PC investigation. T1e
inspectors considered the progress of the licenseets actions and
investigation appropriate and did not identify any safety-significant
issues in the licensee *s individual findings. The inspectors also
identified that the licensee's Operations procedure process does not
contain a requirement or barrier to ensure Operations is notified to
realign a system when an 0P changes the system valve lineup. The
inspectors noted that this was being done informally but was essentially
at the initiative of one individual. The inspectors considered these
deficiencies related to the problems with modification return to service
and procedure impact screening processes discussed in Section E1.2.
Collectively. these findings indicated a weakness in Operations' control
and review of their procedures and their role in modification impact
screening. The inspectors noted that comprehensive revisions to the
procedure and modification change process were being. investigated by the
licensee. The inspector determined these efforts needed tu be
consistent between the Modifications group and Operations to be
effective.
c. Conclusions
The licensee has identified a number of components not in their expected
position, many due to deficiencies in implementing procedure changes.
The inspectors considered Operations' control and review of their
l
,
17
procedures and their role in modification impact screening to be a
collective weakness.
-04 -Operator Knowledge' and Performa1ce
04.1 Ooerator Performance Observations (71707)
On January 10, 1998.. control room operators observed the plant computer
screen display ' irregularly which was indicative of a plant computer
failure. The inspector observed the operators respond to the event by
immediately entering Procedure AP-430, Loss of Control Room Alarms. The
inspector observed that one of the first actions the operators performed
was to verify that the annunciators were operating by i.itentionally
cycling a component to receive an alarm.' This was not an action per AP-
430 and the inspector questioned why it was performed by the operators.
The inspector was also concerned that an inappropriate component could.
be selected and cycled to receive an alarm in the absence of procedural
guidance. The operators had stated they normally cycled a rod position
indication parameter but since that was not available due to plant
conditions, they. elected to cycle a condenser vacuum valve. The
operator initiated a Nuclear Operations Procedure Observations and
Suggestions Tracking (NUPOST) comment for Procedure AP-430 in response
to the inspector's questions.
Upon further review by Operd. e s Department management, the NUPOST
. comment was retracted because it was determined to be unnecessary. A
modification to the computer )rogram that 3rocesses various plant data
for display to the operators lad altered t1e display so that the
operators could clearly see that a problem has occurred with the plant
computer. Additional response time was allowed before the operators
entered procedure AP-430 so that troubleshooting could be performed to
try and prevent entering the AP prematurely. Operations management
determined that there was no need to cycle an annunciator for a loss of
the computer and promulgated this via a Night Order. No further
concerns were noted.
In another observation, the inspector noted that a main steam line
radiation monitor recorder on a back panel on the control board had not
been checked and stamped by the night shift as required per Operations
Instructions (OIs). Consequently, the paper was incorrect by one-half
of.an hour.- This was pointed out by.the inspector but was not corrected
until the next evening when raised again by the inspector. The
parameter being monitored by the recorder was frequently monitored due
to intermittent spiking but the error had not been detected until raised
by'the inspector.
- As noted in Section E2.1. the inspector observed an example of poor
i
Operations questioning and challenging of an engineering operability
assessment. The inspector concluded that these observations indicated
that Operations * questioning attitude and attention to detail had room
f for improvement.
l
18
~
.04.2 Inadvertent Over PressurOation of the Decay Heat letdown Purification
Looo Relief Valve
a. Insoection Scooe (71707)
The inspector performed an inspection of the circumstances of an
operational event involving procedure adherence. '
b. Observations and Findinas
On December 20. 1997, at approximately 6:00 p.m.. the licensee was in
the process of establishing decay heat removal (DH) system purification
through the makeup and purification system. This evolution was being
accomplished in accordance with licensee Frocedure OP-404. Decay Heat
Removal System. The plant operator was directed to detension valve DHV-
105 (decay heat su) ply to the makeup system) prior to the control room
operator opening DiV-75 (letdown filter supply to DH). This action
resulted in pressurizing the line and lifting the relief valve in the
purification . loop. The control room operator took immediate action to
lower the pressure by opening valve DHV-75 when the letdown pressure
alarm was received. Approximately 12 gallons of reactor coolant ,
inventory was discharged to the auxiliary building sump. PC 97-8855 was
issued to document this event and perform a root cause analysis.
The licensee's analysis was completed on January 10. 1998 and was
reviewed by the inspectors. The licensee determined that the primary ,
cause was wrong assumptions by the control room operator who did not I
understand that detensioning the valve would result in pressurizing the
line. Contributing causes were inadequate communication within the
organization, on-the-job distractions time pressure, failure to comply
with expectations for procedure use, inadequate training and inadequate
attention to an equipment problem.
I
The licensee identified that the pre-job briefing did not include a
discussion of the proper method for establishing purification or
previous operating experiences for this evolution. In addition, the
plant operator had not been included in the pre-job briefing and the j
control room operator had not yet referenced the operations )rocedure
for this evolution. DHV-105 was a previously identified leating valve
and had been manually closed and tensioned to prevent the leak. The
licensee determined the operations crew did not consider the
detensioning .of the valve to be part of the procedure. At the time that
this evolution was being performed the control room Senior Reactor
Operator (SR0) was occupied with administrative duties and was not
providing oversight to this evolution.
The licensee recognized a similar event had occurred on October 1. 1997.
--and pursued the resolution of this occurrence thoroughly and swiftly.
Their root cause analysis recognized several related causes to the two
events and proposed appropriate corrective actions. The inspectors
determined that the licensee's root cause was extremely thorough and
very self-critical of the corrective actions taken for the first event.
,
19
Their corrective actions were numerous and comprehensive and included
placing the valve leakage on the Operator Workaround List to heighten
awareness, involving the operator in the corrective action development.
placing tags on the valves to alert operators to the correct
manipulation sequence, and upgrading the knowledge of all operators via
formal training. The inspectors concluded the licensee had adequately
responded to the original event and had implemented appropriate
corrective action. Their response to this second similar non-willful
event constituted prompt, aggressive, and comprehensive corrective
action. Consequently this event is a licensee identified non-repetitive
violation and is being treated as a Non-Cited Violation. NCV 50-302/98-
01-03. Failure to Follow OP-404. Resulting in the Lifting of a Decay
Heat Purificatio.n Relief Valve. per Section VII.B.1 of the NRC
c. Conclusions
A Non-Cited Violation was identified for failure to follow an Operating '
Procedure for aligning a decay heat system purification loop. resulting
in the lifting of a system relief valve. Although the problem had
occurred previously, the licensee recognized their corrective actions
could have been more aggressive and they responded thoroughly and
promptly to the latest example. a
05 Operator Training and Qualification
05.1 Doerations Startuo and Outaae Trainina (71707)
The inspectors observed several sessions of operator simulator and
classroom training for outage changes and plant startup procedures. The
inspectors did not observe any problems during the sessions and observed
that the training appeared appropriate. Management oversight was
present at the startup sessions to reenforce expectations. Startup
evolution performance tasks were distributed to expose a maximum number
of different operators. However, as discussed in section 01.2. it
became apparent during the actual reactor startup that the training
missed an opportunity to reveal rod control procedure problems by only
using simulator initial conditions with all safety rods already
withdrawn.
06 ' Operations Organization and Administration
06.1 Effective February 9. 1998. Sherry Bernhoft became the new Nuclear
Licensing Manager. .
06.2 The following organizational changes were announced on January 6, 1998:
e Reporting to Roy Anderson. Senior Vice President of Energy Supply,
will oe Nuclear Operations. Fossil Operations. Power Marketing.
Administration and the unit's Financial Services.
l'
l
20
-e Nuclear. Operations will be led by the Vice President of Nuclear
Operations, John Paul Cowan. In addition to his current
responsibilities for operations, he will assume responsibility for
Nuclear Engineering and Nuclear Quality Programs.
06.3 The following organizational changes were announced on January 20. 1998:
e Effective March 30, 1998, to allow for several key managers and
supervisors to complete SRO Certification Training, the following
changes will occur:
-
Reporting to John Holden. Director, Site Nuclear Operations .
are:
. Chip Pardee, Director, Plant Operations
e Jim Baumstark. Acting Director. Engineering & Projects
e Bruce Hickle Acting Director, Nuclear Training
-
Reporting to John Paul Cowan. Vice President. Nuclear
Operations, are:
. John Holden. Site Director, Nuclear Operations
e Greg Halnon. Acting Director. Quality Programs
e Mark Marano Director. Site & Business Support
e Bob Grazio. Director. Regulatory Affairs
-
Mike Rencheck. Tom Taylor and Rolf Widell will undergo
Certification Training.
06.4 Effective January 20, 1998, Don Eng was a) pointed Manager of Special
Projects, reporting to John Holden, Site )irector, Nuclear Operations. i
His first assignment is to fully develop two projects for 1998 through {
1999:
e HPI cross-over lines and throttle devices
e Third safety grade EFW pump or Emergency Diesel Generator (EDG)
upgrade to 4150 kw
07 Quality Assurance in Operations )
07.1 Licensee Self-Assessment Activities (71707 and 40500)
The inspectors routinely reviewed various licensee self-assessment
activities and corrective action processes which included review of N0A
surveillance report findings, review of precursor cards entered in to
the corrective action system, and performance of the CARB. The.
inspectors also attended Management Departmental Readiness Reviews
conducted per Procedure AI-256. Revision 2. The inspector observed ;
these reviews were critical and focused on current work backlog and the l
'
ability to support startup and future plant operation. The development
I
21
i
and improvement of meaningful performance indicators was stressed and i
assigned to each department. No problems were identified. l
During routine reviews of Level C PCS when . verifying closure of items of
concern.- the inspectors have identified several deficiencies with the
adequacy of the problem evaluation and corrective actions. Apparent
cause evaluations required for Level C PCS were often cursory or )
inadequate efforts. Corrective actions were often limited to addressing I
the equipment or operational problem, but not the cause for the
condition, and often did not' address the apparent cause. Corrective
action due dates often extended several months beyond when they could
reasonably be ex)ected to be completed. Some specific recent examples
include the two 3CS discussed in IR 50-302/97-19 on a seawater pump. 1
suction blockage and PC 98-0424, discussed in Section 02.1 of this . I
report, on tygon tubing in containment. The inspectors determined that
the Nuclear Safety Assessment Team (NSAT) was.not effectively performing
their role of oversight of the corrective action system because
_
discrepancies such as these were not usually challenged in the PC
closure review. The inspector determined-that Level C PCS needed more
licensee management oversight. Level A and B root causes are required
to be reviewed by the Corrective Action Review Board, which consists
'primarily of senior plant management, but Level C PCS only received a
supervisor review. The licensee agreed with this observation and was
establishing a Corrective Action Review Committee to routinely review a
sample of Level C PCS. The ins)ector considered this an appropriate and -
beneficial response. However, Jased on the observed deficiencies, the
inspectors consider!d the apparent cause evaluations and corrective
actions of Level C precursor cards to be a weakness.
l Another problem with the corrective action system the licensee
identified and the inspectors observed was the amount of. overdue root
cause evaluations. An inspector attended.a Corrective Action Review
Board on January 13, 1998, which addressed the root cause analysis for
two issues: PC 97-8855. discussed in section 04.2, and PC 97-2699. On
l April 17 1997. PC 97-2699 was written to document a failure of the
!. bearing for AHF-14B. The initial screening of the PC assigned the root
l cause to be completed by June 2. 1997. However, the root cause
evaluator was not assigned until August 5. 1997. The root cause
evaluation was initially submitted to the CARB on January 13, 1998. At
, that time, the CARB questioned the number of additional PCS which were
past their due dates for root cause evaluation. On January 16, 1998. PC
98-330 was issued to document that an unsatisfactory population of 31
grade level A and B PCS existed with overdue root cause evaluations,12
of which were over 60 days late. Some of these involved NRC issues
which the inspectors considered to be soor sensitivity to regulatory
problems. The inspectors determined tlat the licensee recognizes the
I problem and is effectively managing it now.
Lic~ nee management is developing a visible and appropriate performance-
. indicator to support managing the problem. The inspector concluded that
NSAT had again performed poorly at effectively informing r,anagement of
I
f
!
22
the true scope of the problem. Overdue items were reported as raw
numbers versus details and actual days overdue.
The inspectors concluded that the licensee's corrective action system
remains adequate but weaknesses were observed with the adequacy of Level
- C precursor card evaluations and corrective actions and the timeliness
of root cause evaluations. Poor oversight by the licensee's Nuclear
Scfety Assessment Team responsible for the corrective action system
contributed to these 3roblems developing. Both issues were being
adequately addressed )y the licensee.
08 Miscellaneous Operations Issues
08.1 (Closed) LER 50-302/96-13-00: Failure to Use Self-Checkino by Doerator
Leads to Unolanned Actuation of Enoineered Safeauards Pumo
a. Insoection Scooe (92901)
During the performance of a monthly automatic actuation logic test
surveillance, a RO improperly aligned a switch and caused a DH pump to
start.
b. Observations and Findinas
During the preparation for a unit startup, a monthly automatic actuation
logic test surveillance was being performed. The RO mistakenly
manipulated the wrong switch resulting in the auto start of decay heat
closed cycle cooling water pump. This system provides cooling for ,
engineered safeguards components. The licensee indicated that the i
personnel error was caused by inadequate self checking. Other
contributors were distractions in the control room, a complicated
procedure, lack of another operator to read the procedure, and similar .
labels on two switches. The inspectors reviewed the corrective actions !
taken to prevent recurrence and considered them adequate. This Licensee l
Event Report (LER) was closed. j
.
c. Conclusions 1
The inspectors evaluated the completed corrective actions and considered
them adequate. This LER was closed.
08.2 (Closed) IFI 50-302/97-11-04: Corrective Actions For Acoroximately 4000
Precursor Cards Not Tracked To Comoletion
a. Insoection Scooe (92901)
'
This inspector followup item (IFI) was opened to track the licensee's
actions to follow up and document corrective actions for approximately
f 4000 PCS that inspectors identified had been closed in late 1996 and
I
early 1997 without ensuring or documenting the completion of corrective
actions.
23
b. Observations and Findinas
The inspectors reviewed the licensee's status on this issue The NSAT
personnel were still in the process of following u) on the brematurely
closed PCS to determine if corrective actions had ]een completed and to
collect documentation of those actions. As of February 2. 1998, they
had determined that 49 PCS had uncompleted corrective actions and needed
to be reopened and 47 were yet to be evaluated. The inspectors
selected 4 of the 49 PCS that were to be reopened and followed up on
them to determine if any significant conditions had not received
adequate corrective action.
PC 96-5314 was dated November 25, 1996, and was graded a C level PC. It
described concerns that boric acid pump testing may not adequately
support Improved Technical Specification (ITS) operability and past
commitments to the NRC. A note written on the PC stated "Further review
may require an operability /reportability evaluation." The apparent
cause evaluation, approved on February 17. 1997, stated that original
ITS requirements for operability and testing of the boric acid pumps
were not properly addressed during the reclassification of the aum3s
under MAR 81-05-15. Therefore, discrepancies existed between t1e rinal
Safety Analysis Report (FSAR). ITS, and testing requirements. An
engineering action _(Engineering Task #2369) was assigned to Nuclear
Operations Engineering (NOE) Mechanical Design Engineering branch, to
track completion and resolution of the issues, with a due date of
March 15. 1997. However, there was no record in the PC file of an
operability or reportability evaluation being done.
Further inspector followup found that, during the System Readiness
Review the system engineer had initiated a new PC 97-2952 on the same
issue. The new PC referenced closed PC 96-5314 and included information
from it. PC 97-2952 was dated April 29, 1997, and was graded a C level
PC. The apparent cause evaluation for PC 97-2952 stated that, as of
July 24, 1997. no response had been received from NOE against Task
- 2369. PC 97-2952 records included a written analysis and disposition
that concluded that the current safety classification and testing of the
boric acid pumps was appropriate.
PC 96-5460 was dated December 2. 1996, and was graded a C level PC. then
reevaluated to a B. and then back to a C. The stated concern was that
Procedure AP-770 aligns pressurizer heaters after a loss of offsite
)ower in a configuration that is inconsistent with Chapter 14 of the
- SAR. This may be outside the design basis and an unreviewed safety
question. This PC had been evaluated as not a design basis issue and
not reportable. The reportability evaluation dated January 7, 1997.
- recommended revising as necessary test and operating procedures. An
i apparent cause evaluation dated May 5. 1997, recommended revision to SP-
910 and AP-770. The inspectors reviewed AP-770. Emergency Diesel
Generator Actuation. Revision 23. dated January 10. 1998, and Procedure
SP-910. Electrical Line Up of the Pressurizer Heaters to an Emergency
Source. Revision 4. dated January 3.1998. and verified that both had
been revised to address the concern.
l
i
f
1
24
l PC 97-0927 was dated February 6.1997, and was graded a C level PC. The
L stated concern was that ITS 5.6.2.17 requires the licensee to submit to
l the NRC changes in the ITS bases, that were implemented without prior
l NRC permission, on a frequency consistent with 10 CFR 50.71. This was
,
not done when the FSAR was submitted in November 1996. The apparent
! cause evaluation stated that personnel involved in missing the required
l submittal time for the ITS Bases had been counseled.and the report was
J being assembled for submittal in March 1997.. The inspectors noted that
the apparent cause evaluation was weak in that it did not address any
i tracking system that should have ensured the timely submittal of the
l required report. Licensee management stated that they would look.into
the controls on ITS Bases submittals.
Inspector followup found that the licensee had submitted a report on
changes to the ITS Bases on April 18.-1997. The PC did not state when
the report was due; however, 10 CFR 50.71 requires that revisions must
be filed annually or six months after each refueling outage provided the
interval between successive u) dates does not exceed 24 months. Since
l the ITS was approved in Decem)er 1993 and implemented in March 1994
during a refueling outage, the inspectors concluded that the report on
changes to the ITS Bases was due by March 1996. Therefore, the report
had been submitted over one year late. This licensee identified and
corrected violation is being treated as a non-cited violation,
consistent with Section VII.B.1 of the NRC Enforcement Policy. It is
identified as NCV 50-302/98-01-04 Late Submittal of ITS Bases Changes.
PC 97-0993 was dated February 21, 1997, and was graded a C level PC. 1
The stated concern was that some electrical cable tray covers required
by the FSAR were missing or damaged. The PC apparent cause evaluation
stated that the electric shop was to walk down and identify cable tray
cover deficiencies in all plant locations and then develop a 31an for
correcting all deficiencies. Inspector followup found that t1is issue
had been addressed by the electric shop under Work Request NU 0345574,
which had been completed and closed on December 28, 1997. I
c. Conclusions
The inspectors concluded that the licensee was working toward
documenting the accomplishment of corrective actions for each PC that
had been prematurely closed. In reviewing a sample of these PCS the
inspectors did not identify any instances where corrective actions were
not being taken. Therefore, IFI 97-11-04 was closed.
During this review, the inspectors identified NCV 50-302/98-01-04, Late
Submittal of ITS Bases Changes. The inspectors also noted a weakness in
the corrective action program, in that it was not always driving the
corrective actions and the corrective actions were not always thorough.
The inspectors assessed the licensee's performance, relative to
corrective actions for this violation. in the five areas of continuing
NRC concern:
l ~
25
s Management Oversight - Adequate-
.- Engineering Effectiveness - Adequate.
. Knowledge of the Design Basis - Adequate
,
. Compliance with Regulations - Adequate
- .- Operator Performance - Not Applicable
08.3 -(Closed)-IFI 50-302/97-14-01: Review of Ooerational Procedures Prior to
Restart
.
a. Insoection Scoce (92901.1
The inspector reviewed various system operating procedures: including
4
the applicable sections of the FSAR and the enhanced design basis
documents, to assure that necessary procedural improvements had been
prior to unit restart.
b. Observations and Findinos
-The inspector reviewed OP-402, Makeup and Purification System and OP-
404. Decay Heat Removal System, to assure that all modifications
completed during the outage were correctly reflected in the procedures.
In addition, the procedure revision tracking system, NUPOST. was
reviewed for outstanding revisions against these procedures and other i
operations procedures. Even though there were a large number of
outstanding editorial-changes for many operations procedures, no
technical changes needed for restart were identified.
The licensee has identified'that there are weaknesses in the )rocedure l
program at the site. A upgrade program is in the process of )eing
developed. The inspectors will continue to follow the upgrade of the
licensee procedure program,
c. Conclusions
The revisions necessary to reflect outage modifications in the system
operating procedures have been completed. This item is closed.
II. Maintenance
M1 Conduct of Maintenance
' M1.1 General Comments
a. Insoection Scoce (62707 and 61726)
Using Inspection Procedures 62707 and 61726. the inspectors observed all ,
i
or portions of the following surveillances and reviewed associated )
l documentation. The following activities were included:
.
L . SP-435 Valve Testing During Cold Shutdown j
,
I
I.
,
lw
l
L
- SP-354B Monthly. Functional Test of the Emergency Diesel
Generator EGDG-1B
( e SP-349B EFP-2 and Valve Surveillance
.
- . SP-102 Control Rod Drop Time Tests
- SP-110D "D". Channel Reactor Protection System Functional
Testing
,
e PM-170C Response Testing of ICS at Power
- b. Observations and Findinas
l
! The inspectors observed the activities identified above and concluded
l
that all work observed was performed with the work packages present and
in active use. Pre-job planning was thorough and in sufficient detail
to prepare the technicians for the assigned tasks. Technicians were
experienced and knowledgeable of their assigned tasks. The inspectors
frequently observed supervisors and system engineers monitoring job
3rogress, and quality control personnel were present whenever required
)y procedure.
i. c. Conclusions
The inspectors concluded that Maintenance activities were performed in
L =accordance with procedures and desired results were obtained.
Specific discussions of maintenance observations are discussed in the
following sections.
M1.2 Intearated Enaineered Safeauards Testina
a. Insoection Scooe (61726)
From January 6 through 11, 1998, the licensee conducted various
- Engineeied Safeguards Actuation Signal (ESAS) testing in preparation for
plant restart. The inspectors observed the majority of testing
-conducted on each Engineered Safeguards (ES) train
'
b. Observations and Findinas
One observation noted was the number (at least five) of IWCCs
. implemented on various ESAS test procedures. IWCCs are considered more
o than minor changes to a procedure. The IWCCs are used for example,'when
i improper information is contained in a procedure step or if the sequence
of steps is not correct or when plant conditions require a different
methodology or equivalent equipment. The use and implementation of-
IWCCs are governed by Administrative Procedure AI-400C. New Procedures
and. Procedure Change Processes.
.
'
l'
i.
[q -
,
'
27
Another observation noted was a non-licensed operator's identification
of a mechanical stopwatch that would not re-zero. The stopwatch had
been used to perform several valve stroke time tests during the
- performance of ES testing and within the preceding week. It was unknown
j . hen the stopwatch began to not reset to zero (kept resetting to 0.1
w
l second). The inspector questioned whether portions of. any testing would
l need to be re-performed because of the stopwatch problem. The testing
l coordinator immediately removed the sto] watch from service and indicated
l he would verify with the Calibration La) oratory (Cal Lab) whether the
l instrument was indeed out of calibration (calibration due date was
5/17/98). He then would determine the impact. if any, on previous valve
- The Cal Lab determined that the stopwatch was within the error allowed
l-
'
by ASME Section XI for valve stroke time tests. This was based on the
fact that the ASME Code requirement for stroke time measurements should
,
be rounded to the nearest second for inservice testing of-valves. In
addition, the licen.see determined that the error was not safety .
l significant because it did not invalidate any of the test data which had
l
been previously obtained. This was based on the review that showed no
data was recorded for any.of the testing that was within 0.1 seconds of
a stroke time upper or lower limit.
L c. Conclusions
l
! The IWCCs generated met the restrictions for use as delineated in
Procedure AI-400C: however, the inspectors concluded that the licensee
could have precluded this process if the procedures had been better
l validated beforehand. The inspectors considered the licensee's actions
in response to the sto) watch issue prompt and aggressive. Overall, the
ESAS testing observed Jy the inspectors was performed in a deliberate
,
and controlled manner, with no significant concerns noted.
l
I- M1.3 Local Leak Rate Testina of Hiah Pressure In.iection Valves
a. Insoection Scone (61726) j
L On January 16, 1998, the licensee performed a local leak rate test
'
(LLRT) on HPI recirculation Target Rock Valves MUV-543/545. The LLRT
was re-performed three additional times because of excess leakage past )
the valves' seats. The inspector observed portions of the LLRT.
b. Observations and Findinas
i
The licensee determined that the first LLRT failure occurred because the
back pressure s)ecification was not properly transmitted / conveyed to the
vendor. When t1e initial request was made to Target Rock, the licensee
failed to specify any back pressure requirements for the valves, so.the
valves were not designed to hold pressure in the backwards direction.
To correct this problem, a Field Change Notice to MAR 96-11-02-01 was
initiated to replace the existing discs with new ones. The new discs
were equipped with two internal ball check valves which would permit the
!
28
4
valves'to be shut, and remain shut, with higher pressure on the
downstream side of the valves.
A vendor representative installed the new discs and another LLRT was
performed on the valves. Again, the valves failed the LLRT when 55
pounds per square inch was applied. The licensee and the vendor then
decided to lap the valve discs in an attempt to provide a better seal
between the valves' seats'and discs. After lapping was completed,
, another LLRT was performed and this time the valves passed
satisfactorily.
c. Conclusions
A local leak rate test on high pressure injection recirculation valves
failed because the licensee oiscovered a required back pressure.
. specification was not properly transmitted or conveyed to the vendor.
Consequently the valves were not designed to withstand the LLRT
backpressure. The inspectors determined that the licensee's corrective
actions to modify the valves were ap3ro]riate because the valves passed
the test. However, the omission of t1e ]ackpressure specification was an
example of poor Engineering performance.
JJI. Enaineerina
El Conduct of Engineering.
E1.1 General Comments (37551)
As the result of deficiencies discussed elsewhere in this and other
<
reports and deficiencies identified by the licensee, licensee management
had initiated several significant changes to programs for design and
l
-
configuration control. On' January 30. 1998, - the licensee suspended the
- use of generic MARS and canceled all existing generic MARS. Generic
MARS were used for re)lacement of similar components in various systems.
However., several of t1ese had remained open for numerous years and
l examples had been observed where their scope was changed to correct an
emergent problem: such scope changes circumvented current design process
,
controls. The licensee also suspended the use of Administrative
! Procedure AI-450, Temporary Power, because examples were observed where
it circumvented appropriate design control processes. The licensee
l evaluated all' existing temporary power installations for adequacy and
l was working to incorporate the program into the Temporary MAR process
!
for all alterations to nuclear )lant electrical systems. Lastly, the
' licensee was reviewing their MAR database to identify inappropriate use
of permanent MfRs for temporary configurations. The licensee was
l- performing this in response to-a finding which identified that a MAR had
!
permanently installed Furmanite repair sealant ports on valves in
containment. Licensee management did not consider that an acceptable
use of a permanent MAR. The licensee issued PC 98-0704 as a grade level
B to document these problems and perform a root cause evaluation. The
inspector concluded that the licensee was effectively addressing
identified problems in their modification process and was applying more
l
l
L
29
conservative management' expectations to longstanding inappropriate
practices.
E1.2 Modification Screenina and Return to Service Process
a. Insoection Scooe (37551 and 92903)
As documented in IR 50-302/97-19. the inspectors identified numerous
discreaancies with tracking of open items for MARS and deficiencies with '
the MAR return to service process late in the re) ort period that would
be:followed up in a subsequent report. During t1e review of
modifications correcting restart items, the inspectors assessed the
adequacy of the licensee's modification design screening and
modification return to service processes. The inspectors also reviewed
the details of numerous licensee identified problems in these areas
documented on PCS.
b. Observations and Findinas
The return tc service (RTS) process is initiated by the licensee's
Projects group that oversees the installation and testing of MARS issued
by Engineering. The process justifies to Operations that the work is
done and the system is ready to be restored to operational status. The
inspector observed that this process was vaguely defined in Nuclear
Engineering Procedures (NEP) and that the RTS packages provided to
Operations reviewers were disorganized and informal inconsistent in
i
level of detail, and contained numerous handwritten notes by Project
,
'
Managers. Although Projects utilized a checklist when assembling RTS
Jackages, it was not part of the RTS package and was not provided to
0)erations to assist in verifying the completeness of the documentation.
t T1e inspector observed that Operations reviewers had develo>ed an
l internal checklist to review the RTS packages which highlig1ted many
i past RTS problems. The inspector also observed that Operations had
, rejected numerous RTS packages for inadequacy. This indicated to the
L
inspector that the quality and completeness of the RTS documentation
provided to 0)erations was poor, and deficiencies were not being
incorporated Jack into Projects procedural requirements.
The inspector also observed that it,was very difficult to assess the
status of MAR open items at any point in the MAR process. Although a
clearly defined list' existed at the initiation of the MAR, open item
responsibility and tracking became scattered as the MAR went through the
stages of implementation. This was particularly evident with required
procedure changes. Projects would track in two separate categories
those required for RTS and those required for MAR closure. However,
these were solely tracked via notes and pages in the MAR package and not
in an effective database. Some items would be internally tracked by
Operations as a RTS exce) tion by placing a procedure on administrative
hold and be unknown to tie Projects department. Other items could be
tracked as Plant Review Committee action items or Corrective Action
System open items and wouldn't be a clear restraint to MAR closure. No
mechanism was provided in the MAR paperwork requirements to track the
30
completion of open items except via handwritten notes. Revisions and
Field Change Notices (FCN) to MARS often added or revised open items
without clearly revising the original list. The inspector also observed
that the MAR design screening process appeared effective at involving
applicable departments to screen for procedure impacts. However, the
documentation of needed changes consisted of only a listing of
procedures needing revision. The scope of the needed change was usually
not defined and could only be determined by querying the department
representative who originally identified the change. Consequently, the
inspector determined it was extremely difficult to verify that the
needed procedure revisions were completed during the RTS review. The
inspector observed several open MAR procedure revisions that werc
annotated as closed based on a revision to the procedure without any
verification that the cited revision actually addressed the specific
needed cnange. The inspector confirmed this deficiency via interviews
with engineers and operators and verified that the required specific
changes had ben incorporated. Although no revisions that had not been
implemented were identified. the inspector determined that the
licensee's 3rocess was poor and has a significant potential for needed
changes to 3e omitted.
Numerous PCS were issued by the licensee during the closure of
modifications and initial operations lineups that identified similar
problems as well as deficiencies in the Design Review Board (DRB)
screenings of the modifications. Some of these are tabulated below:
-
PC 97-8737/C: During performance of SP-338. Remote Shutdown and
Post-Accident Monitoring Channel Check. it was determined that a
MAR removing power to a makeup system valve had not identified SP- l
338 as a procedure that checked the valve and needed to be
revised.
-
PC 98-0115/B: Operators observed that MUV-25 and 26 did not have
Josition lights when performing surveillance. Position light
areakers were discovered to be left open following MAR functional
testing.
-
PC 98-0203/B: Valve WDV-44 - MAR tags found hanging but referenced ,
an inactive MAR work requests had been closed to the MAR. )
However, limit switches had been removed without any procedural
controls indicating a MAR process breakdown.
-
PC 98-0236/C: An OP was not changed to align a new emergency
feedwater flow transmitter (FT) added by a MAR. The FT was
designed to be in service during operation but it's isolation
valves were normally closed in the OP lineup.
-
PC 98-0353/C: The nitrogen systa OP directed the normal position
of four valves to be closed but their labels and the locked valve
i
list required them to be sealed closed.
!
l
1
l
1 l
l J
'\,
.
31
-
PC 98-0450/B: Changes to letdown isolation valves did not result
in.needed changes to valve stroke surveillance procedures.
- - PC 98-0466/ . Change to valve MUV-505 didn't result in SP-436
being revised.
-
PC 98-0748/C: Turbine over speed trip test wouldn't work to latch
turbine because procedure not revised to reflect modification that
added turbine seal in circuit.
-
PC 98-0774/B: An operator discovered that air cylinder isolation
valves were closed while placing a new backup air reservoir system
in service. - The MAR had not specified cylinder isolation valve
positions to be incorporated:into an OP.
The numerous discrepancies identified by the licerisee confirmed the
inspector's observations that significant deficiencies exist with the
licensee's MAR process to support accurate plant procedure and status
control changes. As discussed earlier, the inspector did not identify
any discrepancies that resulted in Noncompliance and the inspector's
review of the licensee's findings also did not result in any
Noncompliance.
c. Conclusions
The licensee's modification process did not support accurate procedure
and plant ecuipment control changes. Tracking of open items was
informal anc scattered in various programs and had a significant
potential for needed changes to be omitted. The format of modification !
return to service packages was poor and informal, which did not support l
the performance of detailed and quality reviews. The inspectors i
concluded the licensee *s modification return to service and procedure 1
impact screening processes were weaknesses. )
1
E1.3 Seismic Adeauacy of Relief Valves
a. Insoection Scoce (37551 and 92903)
The inspectors reviewed corrective actions for a previous violation (VIO
i 50-302/97-17-04) and discussed with licensee Engineering personnel,
l issues associated with NuPro valves. ,
!
!
L
b. Observations and Findinas
IR 50-302/97-17. dated December 29, 1997 documented a violation for not
replacing a NuPro relief valve (DCV-109) as required per MAR 95-10-04-
t
02. Part of the corrective actions for this issue were to review the ,
-documentation that input into the development of MAR 96-10-04-02 to j
determine if other NuPro relief valves were inadvertently not included {
in'the MAR. On January 26, 1998, the NuPro relief valve issue l
resurfaced when an engineer questioned a work request that was initiated I
to repair Nuclear Services Closed Cycle Cooling (SW) valves SWV-287/288. >
l
- _ _ _ _ _ _ _ _ _ _ _ - _ _ _ -
32
One of the o)tions described in the work request was to replace the
valves with quPro valves per Generic MAR 91-08-25-01. PC 98-0563 was
generated to document this issue and assigned a grade level B. As a
result of the extent of condition review for this PC. the licensee
discovered that Makeup and Purification valve MUV-578 was also a NuPro
valve. In addition, the licensee determined that MUV-578 was not
seismically qualified. MUV-578 is a relief valve in the air supply line
for the pneumatic operator of the let h a line containment isolation
valve MUV-49. The extent of condition re/iew for the NuPro valves
seismic concern revealed an additional 35 NuPro valves that did not have
the proper seismic documentation available. As part of the corrective
actions for this issue, the licensee analyzed any seismic concerns
associated with each of the NuPro valves identified and documented
accordingly.
Prior opportunities existed fc- the licensee to resolve the seismic
concern with NuPro valves. The :pparent cause for PC 97-0055 identified
that NuPro RL3 series valves were of less relieving capacity than
previously thought and might not be seismic. The relieving capacity
issue was what led the licensee to replace various NuPro RL3 relief
valves with a different valve (DCV-109 issue). PC 97-6666 documented
that the proceduralized process for seismic qualification of vendor-
supplied safety-related equipment was not being followed. The extent of
condition review for PC 97-6666 noted that the breakdown in the process
for seismic qualificatic, may have resulted in equipment being installed
for which seismic qualification paperwork had not been generated.
10 CFR 50. Appendix B. Criterion XVI. Corrective Action, requires that
measures be established to assure that conditions adverse to quality are
promptly identified and corrected. The failure to correct the seismic
qualification documentation for NuPro valves promptly and the inadequate
corrective actions to ensure all NuPro RL3 relief valves were removed or <
3revented from being used is a violation of NRC requirements. However.
)ecause this failure constitutes a violation of minor significance, it
is being treated as a Non-cited Violation, consistent with Section IV of
the NRC Enforcement Policy. This violation is identified as NCV 50-
302/98-01-05. Failure to Promptly Correct the Seismic Qualification of
NuPro Valves.
c. Conclusions
Although it was determined that this was a minor violation, the
inspectors concluded that the licensee's extent of condition review for
the DCV-109 issue was too narrowly focused. This was based on the
licensee review of documentation for MAR 96-10-04-02 and not NuPro
valves in general. At a later date other NuPro valves were found in the
plant. In addition, poor Engineering performance was noted when prior
roblem existed when Precursor Cards
opportunities for resolution
identified a seismic qualification of a p/ documentation concern but was not
acted upon in a prompt manner.
- - _ _ _ _ _
. - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ .
33
E2 Engineering Support of Facilities and Equipment
E2.1 Throtulino MUV-6/10 in Excess of Vendor's Recommendation May Result in
Valve Body Erosion
a. Insoection Scooe (92903)
The inspectors reviewed the reportability evaluation performed on
January 18. 1998 for an issue identified as a result of the Emergency
Operating Procedure (EOP) inspection.
b. Observations and Findinas
On January 18, 1998. PC 98-0347 was issued to document the throttle
positions for MUV-6 and MUV-10. HPI pumps discharge stop check valves,
do not fall within the manufacturer's recommended range of > 25% open.
Licensee Procedure OP-402, Makeup and Purification System, throttles
these valves to approximately 15 percent and 19 percent open,
respectively. The PC identified that at post accident HPI flowrates,
this may result in some erosion of the valve body.
An interoffice communication from design engineering to the nuclear
shift manager on January 21. 1998, provided the reportability review for
the PC. Discussions with the valve manufacturer identified that at
post-accident flow rates, for up to six months no degradation of the
valve body would be expected. The-review did not address the possible
erosion to the. valve body for throttling these valves to.this position
for extended long term normal operation. The inspector questioned the
normal alignment effects. Design engineers were able to provide the
data that demonstrated that at normal flow rates, no erosion is
expected. The NSM did not have this data, nor had he questioned this-
e
during the reportability review.
c. Conclusions
No concerns exist with the valve position for either normal or post
accident situations. The lack of challenge to the reportability ,
determination by the nuclear shift manager, for not addressing possible
effects in all situations, demonstrated that at times, a lack of
. questioning attitude was still evident.
E8 Miscellaneous Engineering Issues !
E8.1 (Closed) URI 50-302/95-02-02: Control Room Habitability Enveloce Leakaae,
a. Insoection Scooe (92903)
This unresolved item (URI) was summarized and followed up in IR 50-
302/97-19. It~ was left open for licensee post-modification testing of
the control room emergency ventilation system (CREVS), for licensee
testing of the CREVS charcoal filter material, and for NRC review of the
y
t ___ . _ - -
testing. During this inspection. the inspectoc followed up on the
licensee's post-modification testing and chm c. filter testing.
b. Observations and Findinas
The licensee had com)leted the CREVS modifications MAR 97-07-05-01 and
MAR 97-07-00-02 and lad turned over the CREVS to Operations. The
inspectors reviewed the installed modifications. MAR packages, and
completed post-modification testing records and found them to be
adequate.
The licensee had tested the installed CREVS charcoa! filter material and
found that it passed the testing required by the existing ITS
requirements (at least 99% efficient in removing methyl iodide when
, tested at 80 degrees C and 70% relative humidity). but one of the two
trains of charcoal had failed the testing required by the proposed
'
revised ITS requirements (at least 97.5% efficient in removing methyl
iodide when tested at 30 degrees C and 95% relative humidity). The
ins)ectors noted that the licensee had committed to test the charcoal by
bot 1 methods prior to restart. The licensee installed new charcoal in
both CREVS trains and satisfactorily tested the newly installed
charcoal. The inspectors reviewed the charcoal testing results and
confirmed that they were satisfactory.
c. Conclusions
The inspectors concluded that the licensee's CREVS post-modification
testing and charcoal filter testing were adequate. URI 50-302/95-02-02
is closed.
The inspectors assessed the licensee's performance. relative to URI 50-
302/95-02-02, in the five areas of continuing NRC concern:
e Management Oversight - Adequate
e Engineering Effectiveness - Adequate
e Knowledge of the Design Basis - Adequate
o Compliance with Regulations - Adequate
e Operator Performance - Not Applicable
E8.2 (Closed) VIO 50-302/97-02-03: Adeauacy of Procedures to Take the Plant
from Hot Standby to Cold Shutdown from Outside the Controi Room I
a. Insoection Scone (92903)
This violation involved a concern identified by the NRC where the
licensee did not have procedures in effect which provided adequate
instructions for taking the plant from hot standby to cold shutdown from
outside the main control room during an Appendix R fire.
b. Observations and Findinas
The licensee provided the corrective actions for this violation in a
letter to the NRC dated May 23, 1997. The inspectors noted that the
_____-_ _ _ _ - _ _
- _ _ _ _ _ _ _ _ _ _ - - _
35
corrective actions implemented to address this violation were being
tracked under licensee restart item OP-19A. The ins)ectors reviewed
this item previously and documented the results in IR 50-302/97-19. The
inspectors reviewed the corrective actions for compliance with 10 CFR 50'
Appendix R the CR-3 ITS, NRC Safety Evaluation Report (SER)
requirements, the FSAR. and licensee procedures. The ins)ectors noted
in IR 302/97-19 that Abnormal ProceAre AP-990. Shutdown rrom Outside
Control Room, was in the process of 'aing revised at the conclusion of
that inspection. In IR 50-302/97-19, the inspectors raised a question
regarding the number of operations personnel needed to perform procedure
AP-990 and the number of operations personnel needed for the fire
brigade. The inspectors reviewed applicable sections of the CR-3 ITS:
the CR-3 Fire Protection Plan: Administrative Instruction AI-500.
Conduct of Operations and Administrative Instruction AI-2205,
- Administration of CR-3 Fire Brigade Organization. These documents were
l reviewed to detenaine the operations minimum shift staffing and the fire
'
brigade staffing requirements. During this review, the inspectors
gaestioned whether /dministrative Instruction AI-2205 was consistent
with the CR-3 Fire P otection Plan with regard to minimum shift staffing
and fire brigade staffing relative to performance of Procedure AP-990.
The inspectors followsd up on the question regarding minimum shift
staffing and fire brigade staffing during this current inspection which
included reviewing selected operations shift logs for 1996 and 1997 in
order to determine shift manning. During review of the operations logs,
the inspectors determined that shift manning was in accordance with the
requirements of Al-500 and AI-2205 and adequate operations personnel
were on shift to meet minimum shift staffing for performing AP-990 and
for manning the fire brigade. The inspectors further noted that the
licensee had revised AI-2205 to clarify the selection of operations
personnel for manning the fire brigade. The inspectors concluded that
the question regarding minimum shift staffing to perform AP-990 was
resobed.
The inspectors reviewed and walked down the licensee's current draft
Revision 10 to Procedure AP-990, which had been reviewed and approved by
the Plant Review Committee (PRC) but not yet signed by the Manager,
Nuclear Plant Operations. As a result of this review, the inspectors
had several concerns and comments:
e Battery-powered emergency lighting was not provided for locally
tripping the control rod drive (CRD) breakers.
AP-990 (draft Revision 10) required operators to verify at the
remote shutdown panel that the source range nuclear
instrumentation was on scale. If it was not on scale, the
procedure required operators to trip the CRD breakers locally in
the CRD room. A note in AP-990 stated that lighting may not be
available for tripping the CRD breakers. The effective AP-990.
Revision 9, also required o)erators to trip the CRD breakers
locally in the CRD room. T1e inspectors noted that this was the
only AP-990 action to trip the reactor using equipment that was
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_.
- - _ - - _ - . _ .
36-
outside the control room and therefore not potentially affected by
the fire.
The liispectors reviewed the NRC SER dated March 15, 1988. on
Crystal River Fire Protection Issues and the letters from the
licensee on which the SER conclusion that the emergency lighting
was acceptable was based. The inspectors noted that the licensee
had stated to the NRC in a February 4. 1987 letter referenced in.
the SER. that 8-hour battery powered emergency lights were
provided in the CRD room for the AP-990 operator action of opening
.the CRD breakers. In addition, the inspectors reviewed the NRC l
requirements for emergency lighting in 10 CFR 50 Appendix R.
reviewed NRC interpretations of the requirements as published in i
Generic Letter (GL) 86-10. and discussed the issue with both
Region II and NRR fire protection personnel. (10 CFR 50. Appendix ,
R. requires that emergency lighting units with at least an 8-hour I
battery power supply shall be provided in all areas needed for i
operation of safe shutdown equipment and in access and egre.ss
routes thereto.) As a result of this review. the inspectors ,
concluded that battery powered emergency lighting for locally !
tripping the CRD breakers was required by Appendix R. Also, the l
ins)ectors concluded that the licensee's statement, that such
, lig1 ting was installed, was relied upon by the NRC SER approving !
the licensee's emergency lighting plan.
e AP-990 (draft Revision 10) did not require that, following a
manual reactor trip from the control room, operators check the rod
bottom lights to verify that all control rods were fully inserted.
AP-990 was a stand-alone procedure for safely shutting down the
reactor during a fire in the control room. Emergency Operating
Procedure (EOP)-2, the procedure to be used for tripping the
reactor in an emergency, was not to be used in the event of a fire
in the control room. E0P-2 required operators to check rod bottom
lights to verify that all control rods were fully inserted. A
licensed o)erator stated that he would check rod bottom lights
even thoug1 that was not included in AP-990. Licensee Appendix R
and operations personnel stated that the procedure did not
instruct operators to check rod bottom lights because the
indication might be erroneous (due to the fire) and they did not
want operators to perform the E0P-2 response not obtained (RNO)
action of initiating emergency boration based on potentially
erroneous indication. However. AP-990 contained no caution or 1
other information for operators about initiating emergency
boration.
10 CFR 50. Appendix R (as interpreted in GL 86-10), contained no
specific requirements regarding the contents of the licensee's
procedure for ccatrol room evacuation due to a fire. The
inspectors surveyed procedures from nine other nuclear plants. for
control room evacuation due to a fire, and noted that most
required operators to check rod bottom lights.
V . - . .
- .. _ _ . _ _ _ _ . _ _ _ _ _ _ _ _ ~
L 37
p
The inspectors noted that all control room indications and
, controls would be potentially affected by a fire in the control
! room (including the reactor trip button, nuclear instrumentation.
}
'
rod group position indication, and' rod bottom lights). The
ins)ectors reasoned that a prudent. procedure should have operators
loot at available diverse indications of reactor shutdown, at
least all that are required by E0P-2. recognizing that one or more
may be affected by the fire.
e' AP-990 did not require that, following a manual reactor trip.
! operators initiate emergency boration if the reactor was not shut
t
down.
Emergency boration was an immediate action in E0P-2. Operators-
were to perform it immediately and from memory following a reactor
trip if the nuclear instruments did not indicate that the reactor
was shut down. AP-990 did not require emergency boration from
,
inside the control room or from outside the control room. The
! inspectors surveyed procedures from nine.other nuclear plants, for
control room evacuation due to a fire, and noted none included-
emergency boration from inside the control room and some included
emergency boration from outside~ the control room,
e' Based on procedure walkdown comments (other than those discussed
- . above) from the inspectors, licensee personnel stated that they
i would:
. make a local plaque with the procedure for starting the
l . diesel powered air compressor.
4
- revise the AP-990 description of the local incore
,
temperature readout to match the labeling in'the plant, and
[ * move the AP-990 note about lack of lighting for the B MVP
oil pumps to prior to the steps for aligning the B MUP for
L starting.
Prior to restarting the plant, the licensee issued AP-990. Rev.10. as f
,
)
reviewed by the inspectors. Also, the-licensee installed 8-hour battery
powered emergency lights in the CRD room and in the access pathway to
, the CRD room. The inspectors verified these items and concluded that
!
,
the licensee's resolution of the issues related to AP-990 was acceptable
for plant restart. VIO 50-302-02/97-02-03 is closed.
l- :c. Conclusions
l
The inspectors concluded from reviewing operations shift logs that shift
manning was in accordance with the requirements of AI-500 and AI-2205,
and adequate operations personnel were on shift to meet minimum shift
staffing for performing AP-990 and for manning the fire brigade.
l
h
38
The' inspectors concluded that the lack of installed 8-hour battery
powered emergency lights in the CRD room and in the access pathway to
the CRD room.,for the AP-990 operator action of o)ening the CRD
breakers, was a violation of 10 CFR 50. Appendix 1 requirements. This
violation is identified as VIO 50-302/98-01-06. Lack Of Emergency Lights
For Operation of Appendix R Safe Shutdown Equipment.
Also, the-inspectors concluded-that AP-990 was weak in that it did not-
require operators to check rod bottom lights after pushing the reactor
trip button and contained no. guidance on use of emergency boration if
the reactor did not shut down.
.
'-
The' inspectors concluded that the licensee's resolution of issues
-
r
related to AP-990, Shutdown rom Outside the Control Room, was adequate
for plant restart. VIO 50-302/97-02-03 is closed.
The inspectors assessed the licensee's performance, with respect to this
issue. in the five areas of continuing NRC concern:
. Management Oversight - Inadequate
. Engineering Effectiveness - Inadequate
o Knowledge of the Design Basis - Inadequate
. Compliance with Regulations - Inadequate
. Operator Performance - Adequate
E8.3 (Ocen) VIO 50-302/97-16-03: Failure to Desian and Install Radioactive
Waste Discosal System Pioina as Described in the FSAR
(00en) LER 50-302/97-38-00:' An' Encineerina Oversiaht Resulted in.
- Doeration Outside of the Desian Basis for the Waste Disoosal System
a. Insoection Scooe (37550. 92903)
This violation and LER involved the licensee's failure to design and
install portions of the radioactive waste disposal system (WDS) piping
as described in the FSAR. The inspector reviewed the status of the
licensee's corrective actions to address this violation.
b. Observations and Findinos
The inspector reviewed the licensee's response to this violation which
was dated December 17. 1997. The licensee issued LER 50-302/97-38-00.
, on November 22. 1997, to address aspects of this issue. The inspector
( noted that the corrective actions for this violatioc. were being tracked
! under licensee restart item D-51A. Corrective actions specified in the
-
violation response and lER 97-38-00 included the following:
-
Upgrading the liquid and gas outlet piping for the waste gas decay
tanks (WGDT) to Seismic Class I prior to entering Mode 2.
-
Upgrading the liquid outlet piping to Seismic Class I prior to
restart from the next scheduled refueling outage (11R) for the
.
,
39
miscellaneous waste storage tank (MWST), spent resin storage tank
(SRST), and neutralizer tank.
-
Development of a justification for continued operation (JCO) for
the WDS by FPC. consistent with NRC GL 91-18. Revision 1, prior to
entering Mode 4 from the current outage.
{
-
Reactorcoolantdraintank(RCDT)
piping were being evaluated by FPC,process.pibancewith10CFRing
in accor and liqu
50.59. as a change from seismic to non-seismic.
The inspector noted that the modification field work was performed under
modification ap)roval record (MAR) 97-10-01-01. Waste Dis)osal System
Piping Support Jpgrade The modification field work had )een completed
to upgrade the WGDT liquid and gas outlet piping from Seismic Class III
to Seismic I. The WGDTs and the related piping were accepted by
operations on December 23, 1997. for return to service.
The inspector noted that the licensee had 3repared and issued a JC0 and
10 CFR 50.59 safety evaluation for applica)le portions of the WDS liquid
outlet piping. The 50.59 safety evaluation determined that an
unreviewed safety question (US0) existed with the MWST, SRST, and
neutralizer tank not tully meeting the seismic requirements of FSAR
Section 5.1.1.1. The operability determination performed in accordance
with Generic Letter 91-18. Revision 1, provided justification for
-continued operation of the WDS until the piping could be modified and
upgraded to meet the FSAR seismic requirements. The inspector also
noted that the licensee had prepared and issued a 10 CFR 50.59 safety
evaluation to change the RCDT')rocess piping and liquid outlet piping
from seismic to non-seismic. Engineering had submitted documentation
(via interoffice correspondence N0E97-1820 dated November 14, 1997) to
update the FSAR.
The inspector considered the corrective actions completed for violation
50-302/97-16-03 and LER 50-302/97-38-00 were acceptable for restart.
c. Conclusions
The inspector concluded that the corrective actions which had been
implemented for V10 50-302/97-16-03 and LER 50-302/97-38-00 at the
conclusion of this inspection were acceptable for restart. These items
remain open pending com)letion of the other corrective actions specified
in the violation and LER responses. Com)letion of these other
corrective actions will be reviewed furtier during subsequent NRC
inspections.
The inspector assessed the licensee's performance, relative to this
issue, in the five areas of continuing NRC concern:
. Management Oversight - Good
. Engineering Effectiveness - Adequate
. Knowledge of the Design Basis - Adequate
40
- Compliance with Regulations - N/A
. Operator Performance - N/A
E8.4 (Ocen) VIO 50-302/97-16-04: Failure to Follow Procedure CP-111 by not-
Performina a 10 CFR 50.69 Safety Evaluation Within 90 Days After
Identification of a Non-conformina Condition Which Conflicted with the
FSAR DescriDtion
a. Insoection Scooe (92903)
This violation involved the licensee's failure to follow compliance
procedure CP-111 by not performing a 10 CFR 50.59 safety evaluation
within 90 days after identification of a non-conforming condition which
conflicted with the FSAR description.
b. Observations and Findinas
The NRC had evaluated this violation previously and determined that
resolution of this item was.not required prior to restart. The
inspector. reviewed the corrective actions provided in the licensee's
response to this violation which was dated December 17, 1997. These
corrective actions included:
-
Counseling of the engineering personnel responsible for resolving .
PC 97-1515 on meeting the requirements of procedure CP-111.
Processing of Precursor Cards for Corrective Action Program.
-
Completing three Unreviewed Safety Question Determination (US00s)
for PC 97-1515 which included a JC0 for the WGDT liquid and gas
outlet piping, a JC0 for other Waste Disposal System (WDS) tank
liquid outlet Jiping (excluding the RCDT) and a FSAR change to
reflect the RC)T liquid outlet piping as Seismic Class III.
-
Performing an extent of condition review (by January 31, 1998) of
o)en PCs initiated prior to October 1,1997, to determine whether
tie failure to identify nonconforming conditions requiring
performance of a safety assessment /USOD was widespread or an
isolated case.
L The inspector noted that the engineering personnel responsible for
resolving PC 97-1515 had been counseled. The three USODs and the
associated JCOs and FSAR change had been completed. The extent of
L condition review for the open PCs initiated prior to October 1.1997 had 1
not been completed at the conclusion of this inspection. The extent of i
condition review for the open PCs was. in progress and was scheduled to l
l be completeti by January 31. 1998. This violation remains open pending-
'
the licensee's completion of the extent of condition review for the open
PCs. The NRC will review this item during a future inspection.
l
i
c-
j
~
41
c. Conclusions
The inspector concluded that all of the corrective actions for this
violation had not been completed. ' Specifically, the extent of condition
review for the open PCs initiated prior to October 1,1997 had not been
- completed at the conclusion of this inspection. The NRC had evaluated
'this violation previously and determined that resolution of this item
was not required prior to restart. The NRC will review the' extent of
condition review for the open PCs during a future inspection.
E8.5 (Ocen) VIO 50-302/97-16-05: Comoliance with the ODCM Surveillance
Reauirements for the WGDTs
a. Insoection Scoce (92903)
This violation invohed the licensee's failure to comply with Technical
Specification (TS) and Offsite Dose Calculation Manual (ODCM)
surveillance requirements for the WGDTs. The inspector followed u) on
the corrective actions for this violation which were provided-in t1e
licensee's. response dated December 17. 1997.
b. Observations and Findinas
The inspector noted that the corrective actions for this violation
included the following:
-
Making the Chemistry Department personnel aware of this violation.
-
Revising the ODCM to allow use of an indirect method for
determining the quantity of radioactive material in each WGDT.
-
Performing an USQD to support sampling the makeup tank (MUT)
instead of each WGDT.
'
-
Submitting a letter to the NRC by January 31, 1998, clarifying
FPC's implementation of the NRC SER Technical Evaluation Report
statement related to sampling each WGDT.
The inspector interviewed selected Chemistry Department personnel and
determined that the 3ersonnel were aware of this violation. The
inspector verified t1at the ODCM surveillance requirement for the WGDTs
(Section 2.17.1) had been revised to allow use of an indirect method for
determining the quantity of radioactive material in each WGDT. The
inspector noted that surveillance procedure SP-730. Explosive Gas and
Storage Tank Monitoring Chemistry Surveillance Program had been revised
J and was consister,t with t M ODCM revision. The safety assessment /USOD
L' for the revision to proceora SP-730 provided a technical justification
to support' sampling the Mu instead of the WGDT for det.armining the WGDT
Curie content. The licensee considered these changes to be consistent
with the'NRC SER Technical Evaluation Resort. The letter to the NRC
clarifying FPC's implementation of the NRC SER Technical Evaluation
Report had not been submitted by the licensee at the conclusion of this
l i
l
_
42
inspection. This item remains open pending licensee submittal and NRC
review of this letter. ,
.c. Conclusions
The inspector concluded that all of the corrective actions for this
violation had not been completed at the conclusion of this inspection.
S)ecifically, the letter to'the NRC clarifying FPC's im)lementation of
t1e NRC SER Technical Evaluation Report had not been su)mitted.
E8,6 (Ocen) LER 50-302/97-43-00: Deficiency in Electrical Desian Criteria
Resulted in Control Comolex Chiller Motor Trio Set Point Beina Set Belgw
Full Load Amoere Settina
a. !nsoection Scooe (92903)
This LER involved the setting of set points for the chiller motor trip
at lower values than the full load ampere setting. The inspectors
reviewed the LER and other documentation and discussed the problem with
the system engineer.
b. Observations and Findinas
The inspectors discussed the functioning of the control complex chillers
with the system engineer. Not only will the chillers trip on high
amperage on the chiller motor but will also trip on high service water
temperature and high 3ressure in the chiller condenser. The licensee
determined that the cliller ov eload set points of 227 amperes vs vendor
recommended set points of 283 amperes had been incorrect since the
installation of the chillers. However, a REA was issued to determine
the chillers overload set points in January-1992 but set points were not
changed until December 1997 The LER cause section identified this as a
lack of an effective corrective action program.
c. Conclusions
The inspector reviewed the Work Requests for resetting the chiller motor
overload set points and the scheduling priority (before Mode 4) and
concluded that this problem would be resolved before startup. The LER
will remain open until a surveillance procedure is written to test the
set points during each outage. This item is acceptable for restart.
- The inspector assessed the licensee *s penormance relative to resolution
'
of the chiller motor overload set point issue in the five areas of
continuing NRC concern.
e Management Oversight - Good
e Engineering Effectiveness - Good
e Knowledge of the Design Basis - Good
e Compliance with Regalation - Good
e Operator Performance - N/A
!
l
_ _
43
E8.7 (Onen) LER 50-302/97-25-01: Service Water / Raw Water Temoerature
Calculation Contains Non-Conservative Assumotions
a. LnSpection Scooe (929031
This LER discussed an error identified in the calculation of total heat
loads to the Nuclear Services Closed Cycle Cooling (SW) system and
consequently an error in the affected operating procedure curve. The
inspector reviewed the JCO, safety evaluation, and modification for
corcacting this condition,
b. Observations and Findinos
During the evaluation of Restart Item 0-28, engineering discovered that
the analyses performed in 1987 to support the increase in design basis
seawater temperature from 85 to 95 F were deficient.
The analysis assumed only one service water (SW) pump and one raw water
(RW) pump running and the RB fans operating at maximum fouling tactor.
Running two RB fan coolers (assuming the coolers are clean, fouling
factor 0.000 and maximum heat would be removed) and two SW Jumps-
supplying 2000 gpm to ea:h RB fan would provide a considera]ly greater
heat transfer rate into the SW. This condition could cause SW heat
exchanger outlet temperatures to exceed the 110 F limit. Exceeding SW
design basis could cause failure of SW cooled loads and lead to
unacceptable accident mitigation capability.
The licensee revised Calculation M94-0056. Allowable SW Heat Exchanger
Tube Blockage vs Ultimate Heat Sink (UHS) Temperature. Additionally,
operations procedure OP-103B Plant Operating Curves, and associated
Curve 15 were revised to prevent the possibility of exceeding the design i
SW temperature. This procedure assumes two RB fan coolers coming on e 'i
'
maximum heat removal conditions. The inspector reviewed +he F" and *
~
safety analysis and noted that based on data for the UHC G icensee
should be able to operate without a potential UHS tempt m sroblem
until mid-March 1998 (therefore no restart constraint).
The inspector reviewed modification. MAR 97-09-05-01. wh n has been i
installed to allow only one fan to start on an ES actuatic'.. This will
allow the UHS to rise to 95 F (with 0 percent tube blockage). This
modification has been completed, the post maintenance testing aerformed
and removed from service until a Licensing Amendment Request ( AR) is
approved by the NRC. After the approval of the LAR the logic to start
only one pump will be put back in service and the allowable UHS
temperature will be raised. This item was addressed under previous
enforcement action EA 96-365. VIO B (02013): Error in Design
- Cal ulations for SW System Heat Loads.
l
! The inspectors also reviewed a re)ortability evaluation concerning 1
i
tripping of the control complex clillers during a Loss of Coolant
-
Accident (LOCA) that could result in control complex exceeding
temperature limits. The evaluation stated that placing the prerotation
44
. .
vanes of the chiller in " auto" could, during a large break LOCA.- cause
the chiller to trip on high service water temperature. Discussions with
the systems engineer revealed that this is a minor load on the service
water system and that the major load is caused by the RB fans. As
discussed previously the issue of service water temperature was resolved
and therefore will not effect the startup.
c. Conclusions
The inspector concluded that all of the licensee's corrective actions
for this LER had not been completed at the time et this inspection:
however, the licensee actions were acceptable for restart. This item
remains open and will be reviewed further during subsequent NRC
inspections.
E8.8 (Closed) LER 50-302/97-41-00: Control Comolex Chiller may be Rendered
Unavailable due to Desian Error
a. Insoection Scoce (9290_3J
The control logic for the CREVS system tripped and locked-out CREVS for
the condition of ES actuation signal plus " powered from EDG" mode. The
tripping could have occurred in an accident srenario after reset of the
initial ES signal when a second ES signal was received. The inspector
evaluated the information in this LER and inspected the corrective
actions.
b. Observations and Findinas
As stated in the LER, the tripping of CREVS described in the inspection
scope section occurred during an exercise on the plant simulator. The
licensee then evaluated the ramifications of this particular aspect of
the control logic, and determined that it was a problem. Due to time
,
constraints on CREVS being in the off mode. this type of tripping meant
that CREVS might not have fulfilled its safety function of maintaining
the control room envelope temperature within acceptable limits. This {
condition represented a noncompliance with regulatory requirements in ;
the area of Appendix B Criterion III, Design Control. The corrective
action to resolve the issue was to modify the control logic such that
CREVS did not trip for the condition of ES signal plus " powered from the
EDG" mode.
The inspector reviewed the modification package which changed the l
control logic for CREVS equipment. The undesirable tripping and lock-
outs were removed by removing contacts from the control circuits. The
modification package number and title were: MAR 97-11-07-01. 480 V ES/UV
Lockout Logic Change. The modification was implemented in Plant Mode 5,
and the safety evaluation covering Modes 4 through I was contained in J
Field Change Notice No.1 to the package. Records indicated and
engineers stated that the modification was implemented. In addition, ];
the inspector reviewed the licensee's supplementary diesel generator i
loading analysis addressing the ramifications on emergency diesel
45
generator loading of removing the trip signal. In terms of long term
loading on the emergency diesel generators. -removing the trip signal had
no impact as the total load remained tne same as before. For the
scenario of second ES signal after first signal has been reset, removing
the trip on CREVS meant that momentary motor starting loading was higher
than before. The com) uter program indicated that the new momentary
loading value was witlin the emergency diesel gener:1 tor ratings. The
loading analysis was contained in Case Study CSE 97-0043A Impact of
480 V ES Lockout Logic on EDG Scenario Based Steady-State and Dynamic
Analysis.
Although this item is a noncompliance with regulatory requirements.. for
the reasons discussed in Inspection Report 50-302/97-21, the licensee
meets the criteria for enforcement discretion per Section VII B.2 of the
NRC Enforcement Policy as described in NUREG-1600. Consequently this
item is closed and is identified as another example of Non-cited
Violation NCV 50-302/97-21-01. Examples of Noncompliance in Design
Control. 50.59 Evaluations Procedure Adequacy, Reportability, and
l Corrective Actions That Are Subject to Enforcement Discretion.
,
c. Conclusions
l
l Evaluation of the details of LER 50-302/97-41-00. Control Complex
'
. Chiller may be Rendered Unavailable due to Design Error, led to the
conclusion that the licensee's program for identification and resolution
of problems was effective.
l The inspector assessed the licensee's performance relative to this
restart issue in the five areas of continuing NRC concern.
. Management Oversight - Superior.
. Engineering Effectiveness - Superior
e Knowledge of the Design Basis - Superior
e Compliance with Regulation - Good
. Operator Performance - N/A
E8.9 Condition Reoortable Pursuant to 10 CFR 5_0.73(a)(2)(ii)(B). Settina of
Breaker for Motgr Control Center Suoolv Set too Low
a. Insoection Scooe (92903)
On December 9,1997, the licensee identified a condition where the
circuit breaker which controls the supply to safety-related motor
control center ES-3A2 was set low in relation to the maximum
coincidental load on the motor control center. Resolution of this
problem was considered necessary for restart. The low breaker setting
represented a condition outside the design basis in that it could have
resulted in inadvertent tripping of safety-related loads during a
postulated design basis event. This would be contrary to General Design
Criterion 17 which requires an electric distribution system to permit
functioning of systems important to safety.
46
' b. Observations and Findinas
~
The problem with the breaker setting was described in PC 97-8358. The
-inspector- reviewed this PC to determine the s)ecifics of the problem.-
The feeder breaker.for Motor Control Center (iCC) ES-3A2 was located at
480 V bus 3A, compartment:28, and was identified-as breaker 3351. It
was a 480 V power circuit breaker with a solid state tri) device having
a long time and short time element. The problem was wit 1 the setting of
tue long time pick-up. It had been set at 480 A: however, the maximum
coincidental load was recently determined to be 569 A. The inspector
learned through discussions with the cognizant engineers that a
contributing factor to having a breaker setting lower than the load was
the fact that the setting was determined fro:1 system load flow analysis.
The load flow analysis incorporated diversity factors which were
appropriate for that analysis. but not neces.carily for breaker set
)oints. In the case of MCC ES-3A2 the maximum coincidental load on the
l Jus was significantly higher than the load carried in the load flow
study. This problem was identified by the licensee while performing a
l task to review all the' breaker settings for MCC supply breakers, The
- inspector observed that the load on the corresponding bus on the other
L redundant train was less, and its breaker setting was good.
The maximum coincidental load of 569 A was predicated on tagout of the A
l train heater for the BWST, DHHE-2A, which is fed from MCC ES-3A2. The
L
'
inspector agreed that tagout of this heater did not create any safety
concern. The inspector verified that the tag was in place.
, The inspector reviewed the modification package for resetting the long
L time _ pick-u The package number and
l -title were:p set
MAR point from 480Solid
91-08-18-01,' A to State
660 A.Trip Devices 480 V Switchgear
L Circuit Breakers, Field Change Number 7. Revise Breaker Setting for
MTSW-3F-2B, The set point change was not implemented at the time of the
inspection, as the work was awaiting an opportunity to de-energize the
bus. However, the set point change was tracked as a condition for
restart item. The inspector agreed that the set point should be changed
as described above before restart. Otherwise, there was no other
restart issue contained in the Precursor Card or draft version of LER
50-302/97-44-00 rev.iewed by the inspector,
c. Conclusions
The licensee identified a problem with the set point for a safety-
related breaker while performing a general review of breaker set points
for motor control center supply breakers. A modification was prepared
.with the requira.: design control measures to implement a new set point,
and the licrc,ee was committed to implement the change before restart.
The LER scurrently assigned No. 50-302/97-44-00) will be reviewed by NRC
hpectors _after its official issue,
r
I
\
47
E8.10 Reaulatina Transformer for Alternate Sucolv to Vital Bus Not Fully
Oualified
a. Insoection Scone (92903)
Voltage regulating transformers VBTR-4A. 4B. 4C and 4D are in the
alternate supply path to the four channels of vital at buses. The !
transformers are safety-related. On December 13. 1997, as part of
trouble shooting efforts. the licensee questioned the adequacy of the
ratings for these transformers. The licensee determined the condition
was not reportable, and concluded an LER was not required. The irsue
was treated as an issue to be resolved before restart by the NRC and
the inspector reviewed the issue-in this context.
b. Observations and Findinas
The problem with volt. age regulating transformers VBTR-4A. 4B. 4C and 4D
was described in Deficiency Report (DR) 97-8499. The DR had not
received final approval at the time of the inspection. as this was a
recently identified issue.
The subject transformers are ferroresonant ty)e regulating transformers.
The normal supply for.the vital ac buses is tie vital. inverters, one for
each of the.four channels. Technical Specification 3.8.7 allows an
inverter to be out of service for seven days as long as the associated
buses are powered from the alternate source. When powered from the
alternate source, power would flow through the regulating transformers.
The function of the regu4 ting transformer is to provide a more constant
voltage at the vital b an is available at the source. bus. The
transformers were ratea to provide i 1 percent output variation from 120
V with input changes.of + 10/-20 percent voltage.
The issue with the rating of the regulating transformers is as follows.
The transformers are rated 30 kVA at 0.9 power factor (pf). In general.
the power rating of ferroresonant transformers varies with power factor,
i.e. if the load has a lower power factor than 0.9. e.g. 0.6. the
transformer can handle a smaller value of kVA. The calculated load was
23 kVA at 0.518 pf. The calculated load was conservative in terms of
kVA and pf. although it would be difficult to quantify 3recisely the
amount of conservatism. Documentation indicated that tie manufacturer
would not furnish any rating at power factors other than 0.9 because
there was no documented testing at other than 0.9 pf.
-The rationale for concluding that the transformers can perform their
function is as follows. On several occasions the licensee has made
measurements of load and power factor on the vital buses. All these
measurements showed a power factor of about 0.765. The largest measured
load was 14.4 kVA. There was cumulative 4679 hours0.0542 days <br />1.3 hours <br />0.00774 weeks <br />0.00178 months <br /> of operation using
the regulating transforners, most of this during shutdown mode. From
l experience. the load on vital buses did not vary greatly from shutdown
mode, normal operating mode and postulated accident mode. Therefore,
the measured load should be closer to the true worst case design basis
48
l load than the calculated load. The design basis document stated that
the requirement on voltage variations was 5 percent. These values
give considerable margin in terms of kVA. pf and voltage regulation
requirements to cover uncertainties in load determination and power
rating at 0.765 pf.
The conclusion of the licensee's evaluation was that the transformers
were operable but lacked full qualification. The corrective actions in
the Deficiency Report were to provide full qualification before startup
from the next refueling outage (about.1999).
c. C90cNsions
The licensee concluded that the voltage regulat ra transformers. VBTR-
i
4A. 4B. 4C and 4D. which are allowed to provi an alternate source of
power for two sets of vital buses under a Tev.- Kal Specification action
statemer. were operable but not fully qualified. The a) proved
corrective action was to restore full qualification witlin one fuel
cycle. The inspector agreed that the licensee's determination was based
on sound principles and did not represent any significant degradation of )
safety margins.
E8.11 Condition Reoortable Pursuant to 10 CFR 50.73(a)(ii)(B). Circuit Breaker
for Four Valves Set too Low
a. Insoection Scooe (92903)
On December 18, 1997, the licensee identified, as a result of some
ongoing reviews, that the set point on the circuit breaker for valves
MUV-58. MUV-73. BSV-3 and BSV-4 did not meet the design guide. The set
point was too low, and could have resulted in inadvertent tripping of
the circuit breakers upon initial energization of the motor. The
inspector reviewed this issue as an item to be resolved before restart,
b. Observations and Findinas
The aroblem with the breaker set points was described in PC 97-8637.
whic1 the inspector reviewed. The inspector also reviewed the
modification package which established the new breaker set points, and
controlled the change process. The package number and title were: 97-
10-11-01. MCC Motor Circuit Protector Set Point Evaluation. The
inspector observed that correct criteria were applied to determining the
set points for magnetic-only molded-case circuit breakerr of the type i
used on the valves in question. The licensee stated that the change had
already been implemented on the four valves. The inspector selected ;
MUV-58 as a sample, and verified through examination of the equipment !
that the change had been correctly made. The LER will be reviewed by an l
NRC inspector after it is issued. !
l
c. Conclusions !
The licensee identified a problem with the set points on the molded-case
circuit breakers controlling power to four safety-related valves. The
f i
49
set points were corrected through the approved change process. The
change to correct set Joint was verified by the inspector, and the
matter was. closed by' t1e NRC in terms of a restart issue. The LER
(currently assigned No. 97-46) will be reviewed by NRC inspectors after
official issue.
'E8.12 Condition ReDortable Pursuant to 10 CFR 50.73(a)(2)(ii)(B). A Desian.
Error Resulted in the Potential for the Emeroency Diesel Generator to be
Unavailable Durina a Postulated ADDendix R Event
a. Insoection ScoDe (92903)
On December 20. 1997, the licensee identified that the field flash
circuits for the emergency diesel generators did not meet the design
requirements of Appendix R. The field flash circuit included wires that
ran to devices in the control room and these wires were not electrically
isolated from the balance of the circuit As a result of a postulated
fire in the control room, those wires could be short circuited. A
short-circuit on these wires could adversely affect the field flash
function, and render the emergency diesel generators unavailable. The
inspector reviewed the licensee's corrective action for this problem,
b. Observations and Findinas
The problem with the field flash circuits was described in Precursor
Card (PC) 97-8674. which the inspector reviewed. The inspector also
reviewed Field Change Notice No.15 to Modification Approval Record.No.
97-03-02-01. which installed fuses to isolate the control room )ortion -
of the field flash circuits from other parts of the circuit. T1e -
inspector observed from review of these documents that the revised i
design resolved the problem. The licensee stated that the modification j
had been implemented on both redundant trains. The inspector selected -1
EDG B as an inspection sample, and verified that the new fuses were l
installed according to design through examination of the equipment,
c. Conclusions
The licensee identified that the field flash circuit did not meet all
the design requirements of Appendix R. The problem was resolved by the
installation of fuses to isolate control room portions of the circuit.
The inspector verified implementation of the modification. NRC
inspectors will review the LER (currently assigned No. 97-47) after
official issue.
- E8.13 (Closed) LER 50-302/96-05-01 and LER 50-302/96-05-02: Inadeauate Failure
L ,
Modes Review Creates Possibility of Coolina Water Flow Outside of Desian
l- Limits ,
1
'
(Ocen) VIO 50-302/96-01-06: Failure to Correct 1v Translate Desian Basis !
of SW System into Procedures. Drawinas. and Instructions l
l
-
I
i
.
50
sa. Insoection Scone (92903)
y This LER involved the licensee's identification of an unanalyzed failure-
in the SW system. The inspectors reviewed the LERs and supplements, the
previous NRC inspection activities on these items, and the corrective
actions that the lice'nsee had taken.
b. ' Observations and Findinas
The inspectors reviewed the LER background information. During a review
for unanalyzed component failures in the SW system, the licensee
discovered that during certain accident conditions SW inlet and outlet
valves for all three Reactor Building Cooling Units (RBCU) would open
with only one SW aump in operation. During these. accident conditions.
where a. third RBCJ starts, SW total flow would increase and individual
flows would decrease. This is caused by the fact that the SW system is
flow balanced for the operation of only two RBCU at any one time. Three
RBCUs running with only one SW pump running would cause an increased
load on the EDG above its approved load limit and would also result in
g . lower than required flows to individual components.
The root cause.was determined to be an error made by engineering
personnel during the preparation of a design change for the RBCUs which
c
"
did not consider all failure modes. Violation 50-302/96-01-06, Failure
to' Correctly Translate Design Basis of SW System into Procedures,
'
Drawings, and Instructions was issued for this problem. Subsequent
inspections of the LER and the violation (referenced in Inspection
Reports 50-302/96-04 and 50-302/97-13) resulted in the conclusion that
all of the corrective actions necessary for restart had been completed.
0nly one item remains open which is a modification to-incorporate an
interlock' to prevent loading two RBCUs on one EDG and exceeding its
loading limits. The LER is closed and this item will be tracked by the
.open violation.
c. Conclusions
The inspector evaluated the corrective actions completed, reviewed other
documentation, and concluded that the LER could be closed and that the
open violation could be utilized to track the modification that would
incorporate an interlock.
- The inspector assessed the licensee's performance relative to resolution
of the possibility of cooling water flow outside of design limits in the
five areas of continuing NRC concern.
~
e Management Oversight - Good
e Engineering Effectiveness - Good
e Knowledge of the Design Basis - Good
. Compliance with Regulation - Good
. Operator Performance - N/A
51
E8.14 (Closed) LER 50-302/96-23-00 and LER 50-302/96-23-01: Personnel Error
Leads to Missed Surveillance Resultina in Violation of Technical
Specifications
a. Insoection Scooe (92903)
The licensee removed a surveillant for a channel check for the motor
driven (MD) EFW pump discharge preture instrument from one surveillance
procedure and placed the requirement in another procedure. The time
interval changed and caused a violation of TS requirements. The
inspectors reviewed the LER information, an associated violation, and
corrective actions taken by the licensee.
b. Observations and Findinas
-
During a review by NRC inspectors of Surveillance Procedure SP-338.
Remote Shutdown and Post Accident Channel Check, it was noted that a
channel check for MD EFW aum) discharge pressure gauge was not included
in the procedure. This ciecc was required by TS Surveillance
Requirement 3.3.18.1. A further check indicated that the requirement
was moved from SP-338 to Surveillance Procedure SP-349A. EFP-1 and Valve
Surveillance. However the frecuency of the surveillance changed from
monthly for SP-338 to every 92 cays for SP-349A. which violated the TS
surveillance interval. Violation 50-302/96-15-01. Failure to Perform a
Required TS Surveillance for the Remote Shutdown Panel, was issued for
this problem.
The inspectors reviewed the following corrective actions taken by the
licensee: event reviewed with -personnel responsible for the error; the
procedure change process procedure was revised to provide a more focused
technical review; and noted that appropriate procedure changes had been
made to comply with TS surveillance requirements. Two other corrective
actions are scheduled for completion 90 days after restart of the unit:
one concerning calibration and channel check procedures and another
concerning an in depth Appendix R review and revision. These two open
corrective action items were not necessary for restart and will be
tracked by the open violation. LERs 50-302/96-23-00 and 50-302/96-23-01
are closed.
c. Conclusions
The inspector evaluated the corrective actions completed, reviewed other
documentation, and concluded that the LER would be closed and that the
open violation would be utilized to track the two remaining open
corrective actions.
!
E8 15 (Closed) EA 97-330. VIO B (01023): Failure to Uodate the FSAR to Include
Added EDG Trios
'
a. Insoection Scooe (92903)
This violation involved the licensee's failure to update the FSAR for a
modification to the EDG automatic trips that was installed in 1987. The
i
1
i
E
_
,
52
=
inspectors followed up on the licensee's corrective actions for the
violation.
,
.b. Observations and Findinas-
The inspectors reviewed FSAR Revision 14. dated January 26. 1998, and
verified that the current FSAR description of the EDG trips correctly
'
described the current' installation in the plant, as reviewed and
approved by tha NRC in License Amendment 159, dated December 1, 1997.
The' inspectors verified that the Configuration Document Integration
Project (CDIP)..which had produced Revision 24 to the FSAR. was-to-
continue to. operate for about another six months to produce Revision 25
to the FSAR. After that, the licensee planned to continue using an FSAR
u) dating process similar to CDIP, using fewer people who would be within
tie nuclear licensing group. The new process was to be described soon
t
in a new procedure. CP-216. Maintenance of the FSAR. The new process-
! was to continue the System Ownership Teams, lead by the system
engineers.
The inspectors also verified that the licen" ' had benchmarked the
regulatory process for updating the FSAR. u . ing trips in early-1997 to
the V. C. Summer and Davis Besse nuclear plants, and had documented that
l effort in a " Licensing and Regulatory Performance Bench Marking Report"
dated March 28, 1997. The results of.the benchmarking had been factored
into the Configuration Document Integration Project Process' Guide, dated
^ July 28, 1997. The inspectors had previously reviewed the 10 CFR 50.59
process that was upgraded in March 1997, and had verified that licensee
,
personnel were trained on the revised process.
!-
.
.c. Conclusions
l The inspectors concluded that the licensee's co rective actions had been
implemented and included actions to
EA 97-330. VIO B (01023) is closed. prevent recurrence of the violation.
The inspectors assessed the licensee's performance, relative to
corrective actions for this violation, in the five areas of continuing
NRC concern:
.- Management Oversight - Good
L.. Engineering Effectiveness - Good
. Knowledge of the Design Basis - Good
. Compliance with Regulations - Good
. Operator Performance - Good
E8.16 10losed) URI 50-302/96-201-06: Preferred Offsite Electrical Power Source
With Plant Shut Down (500 KV Switchyard) is Not Qualified
a. Insoection Scooe (92903)
This issue involved the licensee's prior use of the 500 KV switchyard,
backfeeding through the unit step up transformer, as a source of offsite
53
l power for safety-related busses when the plant'was shut down. ITS Bases
3.8.1 stated that the 500 KV backfeed was a qualified source of power
for this mode of operation. However, the licensee had no calculations
to demonstrate the adequacy of the 500 KV backfeed. The inspectors
followed up on this URI.
b. Observations and Findinas
!
The inspectors reviewed documents as listed below and discussed this URI
with licensee engineers and Licensing personnel.
-
Calculation E-96-0004: 500 KV Backfeed Voltage Drops. Load Flow,
Motor Starting, Short Circuit, and Parallel Operation Analysis:
. Revision 0. dated August 21, 1997
-
Design basis document changes approved by the Plant Review
l Committee along with Calculation E-96-0004: including changes to
'
ITS 3.8.1 and 3.8.2 Bases. FSAR Section 8.2.3, the Design Basis
Document, and the Enhanced Design Basis Document
-
ITS 3.8.1. AC Sources - Operating: ITS 3.8.2, AC Sources -
Shutdown: and the Bases for both of these ITS
-
FSAR Section 8.2.3: Sources of Auxiliary Power: Revision 24, dated
January 26. 1998
-
Procedure OP-703A: Establishing, Maintaining,'and Removing 500 KV
L Electrical Power Backfeed: Revision 9 dated December 5. 1997: and
Revision 8. dated August 28, 1997
-
Records of past performance of OP-703A in 1986 and 1987 and-
, related operator logs
-
Procedure SP-301: Shutdown Daily Surveillance Log: Revision 106,
dated January 20, 1998
-
Procedure SP-321. Power Distribution Breaker Alignment and Power
Availability Verification: Revision 41, dated December 24. 1997:
-
Interoffice Correspondence from Nuclear Operations Engineering to
FPC Energy Control in St. Petersburg; regarding administrative
controls on the 500 KV switchyard voltage required by Calculation
L E-96-0004, Revision 0: dated August 23, 1997:
-
Interoffice Correspondence from FPC Energy Control: regarding
Crystal River Plant 500 KV voltage: dated September 23, 1997
The inspectors noted that Calculation E-96-0004 concluded that the 500
KV backfeed was a qualified source of offsite power for safety-related
buses when the plant was shut down in Mode 5 or 6. provided that certain
administrative controls were in place. These administrative controls
included maintaining 500 KV switchyard voltage between 515 and 530 KV,
54
limiting the number of safety and non-safety buses and loads on the 500
KV backfeed. and limiting the amperes on the 500 KV backfeed.
URI 50-302/96-201-06 was described in NRC inspection report (IR)96-201,
which was issued on August 23. 1996. Ins)ector review of operating
records prior to that time found that in March 1996 the licensee had
exceeded the limits of the administrative controls required by
Calculation E-96-0004 and its safety evaluation. The records indicated
that the licensee had loaded both 4160 V ES Buses, both 4160 V Unit
Buses, plus the 6900 V Reactor Auxiliary Bus 3A on the 500 KV backfeed.
Calculation E-96-0004 restrictions, as implemented in OP-703A. limited
loads on the 500 KV backfeed to one 4160 V ES Bus, no 4160 V Unit Buses,
and the 6900 V Buses with loading limited to the RB Chiller and FWP-7.
The system engineer stated that past practices included routinely
loading all safety and non-safety buses on the 500 KV backfeed when the
plant was shut down. ITS 3.8.2. AC Sources - Shutdown, requires one
qualified circuit between the offsite transmission network and the
onsite Class IE AC electrical power subsystems. The inspectors
concluded that in the past (e.g., in March 1996) the licensee had not
complied with ITS 3.8.2 in that they did not have a qualified circuit
between the offsite transmission network and the onsite Class 1E AC
electrical power subsystems when they used the 500 KV backfeed. In
response to this issue, the licensee initiated PC 98-0271.
On August 22, 1997, after approving Calculation E-96-0004 and issuing an
immediate distribution copy of related Rev. 8 to OP-703A. the licensee
placed the 4160 V ES Bus 3B on the 500 KV backfeed. The inspectors
reviewed licensee administrative controls required by the safety
evaluation and those in place at that time. The 10 CFR 50.59 safety
evaluation for the calculation stated that the administrative controls
will require operator actions for breaker alignments and monitoring of
switchyard voltages and associated bus and transformer loading to assure
that the limitations summarized in the safety evaluation are maintained.
The inspectors noted that OP-703A implemented the administrative 4
controls of Calculation E-96-0004 when the safety-related buses were
placed on the 500 KV backfeed. However. OP-703A did not require
operators to ensure that FPC Energy Control in St. Petersburg was
implementing the s)ecial monitoring and control of the 500 KV switchyard
7
voltage, as descri Jed in the Interoffice Correspondences (IOCs) listed
above. (NOTE: The Crystal River 3 control room did not have indication
or control of 500 KV switchyard voltage.) The licensee's process for
control of agreements between CR-3 and other organizations was to enter
them into the controlled "CR-3/0ther Interface Matrix." However, this
agreement with the ECC was not in the control room copy of the "CR-
3/Other Interface Matrix." Also, there were no night orders or Short
- Term Instructions for operators to alert them about the needed
L administrative controls or the existence of the agreement with the ECC.
The inspectors reviewed the status of the nine )rocedures that the
calculation review package indicated needed to )e changed. The
calculation review package stated that only one (OP-703A) needed to be
changed prior to the next 500 KV backfeed usage. The inspectors noted
l
that two of the other.eight procedures to be changed. SP-301 and SP-321.
r
55
1
l' had not been changed to include requirements for o)erators to monitor
switchyard voltages periodically (or assure that PC Energy Control was
monitoring them), associated bus and transformer loading, or breaker
alignments. The tracking system used by the licensee to ensure that
these procedure changes were completed was the NOTES system: however,
these needed procedure changes were not tracked in NOTES. <
A review of operating records found that the 500 KV backfeed had been
used to power one ES bus on six different occasions during August 1997
'
l through January 1998. On each occasion, only one ES bus and no non-
L safety buses were powered from the 500 KV backfeed The electrical
design engineer an'd system engineer stated that. with that alignment,
the ampere limits of OP-703A could not have been exceeded. While the
ECC maintained no log of the 500 KV switchyard voltage, they had an
alarm that would actuate before the switchyard voltage went outside of
the 515 - 530 KV range. ECC operators did not recall getting an alarm
or going outside the 515 - 530 KV range during August 1997 through
January 1998. The inspectors concluded that, during August 1997 through
January 1998, the licensee had probably not exceeded the 500 KV backfeed
l limits of Calculation E-96-0004. However, the licensee had used the 500
KV backfeed to power a safety-related bus without having adequate
)rocedures for operator monitoring of switchyard voltages, associated
aus and transformer loading, or breaker alignments. In response to this
issue, the licensee initiated PC 98-0729.
l
The inspectors reviewed the changes to the ITS Bases. FSAR. and Enhanced
Design Basis Document (EDBD) that had been approved by the PRC and
Director. Nuclear Plant Operations (DN)0) along with Calculation E-96-
0004. The inspectors noted that the c;rrent Bases for ITS 3.8.1. AC
Sources - Operating, incorrectly statei: "When the CR-3 generator is not
producing power. a qualified offsite power source is the backfeed from
the 500 KV substation through the Unit 3 step up transformers and the
Unit 3 auxiliary transformer." This statement was incorrect because ITS
3.8.1 ap)1ies only in Modes 1 - 4 and Calculation E-96-0004 stated that
the 500 (V backfeed may only be used in Modes 5 and 6. The change to
ITS Bases 3.8.1 that was approved by the PRC and DNP0 (but not yet
incorporated into the published ITS) incorrectly left that statement in
. place, and revised it to add that the 500 KV substation "can be used as
a source of offsite power subject to certain voltage and loading
constraints, and administrative controls." Also, the approved changes
to ITS 3.8.1 and 3.8.2 Bases did not state what the required
administrative controls were, either directly or by reference. The
approved changes to the FSAR and EDBD also did not describe the required
administrative controls. The inspectors concluded that the operators
were not properly informed of the administrative controls necessary to
implement the requirements of ITS 3.8.2 and therefore were not fully
prepared to be in charge of correctly implementing the ITS.
The inspectors inquired about when the changes to the ITS Bases, that
had been approved by the PRC and DNPO. became official and were
disseminated to plant personnel. The inspectors were told, by a
L Licensing representative, that these changes were not yet official and
'
that_they needed further review and approval by Licensing. Also. ITS
L
56
Bases changes made by the licensee under 10 CFR 50.59 were not
disseminated to )lant personnel on the plant coraputer. The inspector
noted that the clanges to the' FSAR became official when they were-
approved by the PRC and DNP0 and they were then disseminated to plant
personnel on the computer. The inspectors assessed that there were
)otential weaknesses in the licensee's control of ITS Bases changes.
_icensee management stated that they would look into the control of ITS
Bases' changes.
c. Conclusions
The inspectors identified a violation of ITS 3.8.2 in that the 500 KV
backfeed was not qualified when used in the past (e.g., in March 1996)..
.This-issue is identified as VIO 50-302/98-01-07, 500 KV Backfeed Not c
Qualified Source of Offsite Power.
The inspectors also identi fied that adequate procedures were not in
place for use of the 500 KV backfeed during August 1997 through January
1998. This issue is identified as VIO 50-302/98-01-08. Inadequate
Procedures for Use of 500 KV Backfeed.
'E8.17 (Closed) LER 50-302/97-45-00: Containment Isolation Valves'Not
Seismically Oualified Due to an Installation Error (92903)
On December 5.1997, the licensee discovered Chemical Addition System
(CA) valve actuators for CAV-6/7 were not restrained as originally _
designed. These one-inch valves are outside containment isolation
valves (CIVs) and are on two separate lines. The condition was not
previously identified because one-inch valves are exempt from inspection
and examination in accordance with the licensee s Inservice Inspection
Program. In the event of a seismic event, the otential exists for a
containment-breach pathway to the adjacent Auxi iary Building (AB) via
one or both of these valves. A subsequent failure of the inside CIVs
could result in a radiological release to the AB.
The apparent cause for this event as determined by the licensee was
. personnel error. The supports for the actuators were to be installed
during original construction, but the specified supports did not fit the
actuators. An engineering field change to correct the supports was
never implemented. The corrective action recently implemented was the
installation of the necessary supports to return the valves to Seismic
Class I. In addition, a review of similar small-bore outside CIVs was
done with no similar conditions identified. The inspectors considered
the licensee's corrective actions to be appropriate and acceptable.
Although this item is a noncompliance with regulatory requirements, for
the reasons discussed in Inspection Report 50-302/97-21., the licensee
L meets the criteria for enforcement discretion per Section VII.B.2 of the
! NRC Enforcement Policy as described in NUREG-1600. Consequently, this
'
item is closed and is identified as another example of Non-cited
Violation NCV 50-302/97-21-01. Examples of Noncompliances in Design
Control. 50.59 Evaluations. Procedure Adequacy. Reportability, and
Corrective Actions that are Subject to Enforcement Discretion.
1
57
The inspectors assessed the-licensee's performance, with respect to this
issue, in the five areas of continuing NRC concern.
- Management.0versight - Adequate
- Engineering Effectiveness - Adequate
e Knowledge of Design Basis - Adecuate
e Compliance with Regulations - Acequate
- Operator Performance - N/A
l E8.18 (Closed) LER 50-302/95-23-01 & 02: Inconsistent Desian Assumotions Cause
luildina Soray Pumo Flowrate Concerns Resultina in Ooeration Outside the
)esian Basis (92903)
This issue was first identified during the licensee's Emergency
0)erating Procedures (EOP) Enhancement Program back in October 1995.
T1e NRC issued a Non-cited Violation (NCV 95-18-03) for failure to
translate the design basis correctly for the reactor building spray (BS)
l system into design specifications. The issue was again discussed in
- Inspection Report 50-302/96-04 when LER 95-23 was closed after NRC
i inspectors performed a review to assure that the licensee's corrective
1 actions had been completed and that assumptions in the affected
calculations were reasonable. Supplements 1 and 2 to LER 95-23 revised
corrective action completion dates. Supplement 2 also provided a
i revision to the previous corrective action completion schedule for a
l change to a design basis document. Specifically, the Enhanced Design
L Basis Document and Analysis Basis Document were revised to incorporate a
l
'
lower BS flow rate limit acceptable for iodine removal capacity in the
reactor building. The inspector reviewed the corrective actions and
verified completion. No further concerns were identified. LERs 95-23-
01 and -02 are considered closed.
E8.19 Review of the Additional Information for License Amendment Recuest #224.
Reactor Buildino Fan Startina Loaic Modification
a. Insoection ScoDe (92903_1
On January 9, 1998, the licensee submitted additional information for
LAR 224, Reactor Building Fan Starting Logic Modification. The
inspector reviewed the information, including the Failure Modes and
Effects Analysis (FMEA) for the modification,
b. Observations and Findinas
On January 9. 1998, the licensee submitted an FMEA completed by a
contract engineering firm to address the reactor building cooling fan
logic modification. The FMEA provided a qualitative assessment of the
effects of failures of the various components that are part of the fan
control logic modification detailed in MAR 97-09-05-01. The objective
of the FMEA was to determine whether the design satisfied the single
failure criteria. The modified logic was evaluated for its ability to
accomplish the required function of preventing two reactor building
!
58
cooling fans from running simultaneously following a large break LOCA.
The FMEA concluded that there were no credible failures for the
component in the RB cooling fan control circuits that would-result in.
two fans that could continue to run at the same time following the
initiation of an Engineered. Safeguards Actuation System (ESAS) signal.
!
The ins)ectors reviewed the submittal. In Section 3.
System /.iodification Description, the FMEA stated that due to emergency
diesel generator loading considerations, the circuit modifications had
been designed.to make the A fan the preferred fan and the B fan the back
up, the A diesel having more margin than the B. The. inspector
identified that this statement was in error., the A diesel has less
margin than the B. AHF-1A was chosen as the preferred fan, loading onto
EGDG-1A. to make it less likely to start out of sequence on the more
heavily loaded diesel generator.
On January 13, 1998, the licensee issued PC 98-0250, to document that
the error existed in the FMEA after discussions with the inspector. In
response, the licensee is preparing a revision to the FMEA, with a
correction to this statement.
c. Conclusions
Licensee review of the submittal failed to identify the erroneous
statement concerning the emergency diesel generator loading. Attention
to detail is needed to assure that accurate information is transmitted
to the NRC.
E8,20 (Ooen) LER 50-302/97-13-00: Functional Testina of EDG-1A Room
Temoerature May Exceed-120 dearee F
f00en) LER 50-302/97-19-00 and 50-302/97-19-01: Elevated EDG Suoolv Air
~
emoerature Due to EDG Radiator Discharae Air Recirculation Effect
(00en) LER 50-302/97-27-00: Failure to Add Antifreeze to the Diesel )
Generator Coolant Radiators May Render EDG Inocerable Durina Subfreezina
Temoeratures
a. Insoection~Scooe (92903)
The inspector reviewed corrective actions taken to resolve issues
identified in various Licensee Event Reports (LERs) concerning emergency
diesel generator design deficiencies.
b. Observations and Findinas
Modifications im)1emented to address the design issues addressed in
these LERs have 3een addressed in IR 50-302/97-19.
Final corrective actions to the problem with recirculating discharge
air., as described in LER 50-302/97-19-00 and 50-302/97-19-01 will be
addressed by the building of a deflection wall at the exhaust point. to
l
,
59
i
prevent recirculation into the cooling air inlet. This modification is l
schedaled to be complete prior to March 31. 1998. The licensee 1
3rocessed a Justification for Continued Operation (JCO) via their )
Jeficiency Report Process described in CP-111. Processing of Precursor
Cards in the Corrective Action System. This is the licensee's process
for implementing operability options described in NRC Generic Letter
(GL) 91-18. Revision 1. for operation until completion of the
modification. This JC0 was also used to justify operation with .
incomplete corrective actions for LER 50-302/97-13 and LER 50-302/97-27. '
The inspector reviewed the Deficiency Report and JC0 issued to address
these corrective actions. The licensee concluded that EGDG-1A and EGDG-
1B are capable of performing their design basis functions provided three
design basis conditions are met: engine room maximum temperature does
not exceed 120 F, engine combustion inlet air maximum temperature does
not exceed 105 F. and radiator room su) ply air maximum temperature (for
winter operations) does not exceed 95 :.
The licensee concluded that the winter operation design basis supply air
temperature for the radiator room is 95 F and supports continuous EDG
operation. Based on the potential for 14 F recirculation penalty, the
maximum outdoor ambient air temperature is reduced to a limit of 81 F.
An additional 5 F increase in radiator room supply air temperature is
permitted, based on studies from the EDG manufacturer. Based on this
study, a maximum outdoor ambient air temperature of 86 F is permissible
l for winter operation. The licensee JC0 stated that the maximum outdoor
! ambient air temperature of 86 F will be monitored from the
Meteorological Tower (33' elevation) or the contingent location. The
licensee JC0 called for increased monitoring above 81 F and declaring
l the emergency diesel generators Poperable above 86 F. These actions
I
would be in place until the defk cion wall modification was completed.
The JC0 identified that the amount of antifreeze added to the radiators
to protect against freezing at the lowest expected winter temperatures-,
decreased the heat transfer capabilities of the coolant to the point
that sufficient heat could not be removed at elevated ambient
temperatures (above 86 F).
The inspector attended the Plant Review Committee (PRC) presentation of i
the JC0 on December 22, 1997. The PRC opened several items which needed
to be resolved prior to final approval of the DR/JCO. These items
included: (1) Address guidance on how to implement the 81 F monitoring.
(2) Address the criteria for transitioning from winter to summer
o)erations. Ensure there are administrative controls to cover the
clange. (3) Develop a contingency plan for the meteorological towers ;
being out of service. These items were clarified following a revision !
to the JCO. which was presented to the PRC on December 29. 1997.
Tracking was established to assure that revisions were made to all plant
procedures which address emergency diesel generator operation and daily
operations surveillance procedures.
On January 5.1998, the inspector questioned whether interim actions had
been implemented to provide monitoring requirements and contingency
. -)
i
I
l
l
!
60 i
'
actions for elevated temperatures. On that date, the licensee
recognized that no administrative controls were in place. Discussions
with various licensee personnel revealed that the consensus opinion was
, that the-JC0 was.for Mode 4 and above o)eration which was not yet
. applicable. The inspector noted that t1e JC0 was.actually written for.
'
winter month operation and was mode independent. The licensee issued a
Short Term Instruction-(STI) to provide guidance and controls for the
operators, until revisions were issued on the normal licensee
procedures.
, c. Conclusions
Various licensee perscnnel reviewed and approved the implementation of
the JCO. but the misconception existed that the JC0 was mode dependent
instead of being restricted to winter operation. The PRC review of this
' document resulted in several requirements for contingency actions and
administrative controls to be in place )rior to final implementation.
Even though revisions were submitted, tie licensee neglected to
implement interim controls.
When the administrative controls were verified to be implemented, all
corrective actions for the emergency-die.sel generators, necessary for
unit restart, were completed. The LERs will remain open pending the
final completion of the remaining modifications, but are acceptable for
restart.
E8.21 Followuo of Boron Precioitation Thermocouole Modification
a. Insoection Scooe (92903)
The inspectors reviewed the completion of MAR 97-12-01-01 which
installed thermocouples as a proposed revision to License Condition
2.C(5).
b. Observations and Findinas
On January 27, 1998. License Amendment 164 was issued which deleted the
requirement from License Condition 2.C(5) relating to installation and
testing of flow indicators in the emergency core cooling system to
provide indication of 40 gallons per minute flow for boron dilution.
This amendment also incorporated a new license condition. 2.C(11). which
requires that a system of thermocouples added to the decay heat (DH)
drop and auxiliary pressurizer spray (APS) lines. ca)able of detecting
flow initiation, shall be operable in modes 4 througl 1. The license
condition requires that channel checks be performed monthly basis to
demonstrate operability. If either the DH or APS system thermocouples
becomes inoperable, operability shall be restored within 30 days or the
NRC shall be informed, in a Special Report within the following 14 days.
The inspector verified that the MAR was returned to service at 11:37
3.m. on January 10, 1998. The inspector reviewed licensee procedure.
400-31 and determined that it was revised to include the operability
- ________
61
requirements specified in the license condition on January-15.1998. On
January-12.-1998, the ins)ector discussed the modification with control
room personnel. The on-slift personnel were unaware that the
modification had occurred and that the new thermocouples were to be used
to prevent boron precipitation. .A senior reactor operator in training
made the shift and the inspector avfare that an OSB entry had been
issued on the modification on December 29, 1997. The inspector verified
that the operations personnel who were unaware of the modification had
signed the OSB entry as having been read. On January 29, 1998, at 9:07
p.m. the Nuclear Shift Manager entered the N00-31 actions for the
thermocouples being inoperable, based on a mismatch of greater than
15 F. This acceptance criteria was in a draft revision to SP-338.
Remote Shutdown and Post Accident Monitoring Channel Check, which was
undergoing validation. Engineering dispositioned this issue by
concluding that the criteria within the proposed channel check procedure
was not correct for the installed configuration. SP-338 was issued on
February 3.1998, with revised acceptance criteria for the thermocouple
channel check. .
c. Conclusions
The licensee has installed administrative controls and hardware
modifications which adequately address License Condition 2.C(11), as i
described in License Amendment 164. The declaration of the i
thermocouples as inoperable based on acceptance criteria in a draft
procedure revision was a conservative approach by the operations
department. The dispositioning of the issue by engineering, which
determined that the acceptance criteria were not correct, demonstrated
- that weaknesses existed during the review of the procedure revision. l
E8.22 (Closed) IFI 50-302/95-02-05: Resonance Noise in Vicinity of MUV-25
l
a. Insoection Scooe (92903) l
The inspector reviewed the actions taken by the licensee to address l
apparent resonance noise in the makeup system in the vicinity of MUV-25. j
b. Observations and Findinas l
Following the identification the postulated resonance noise in the
makeup system, the licensee has performed a large amount of monitoring
l. in the system. The noise is a low energy high frequency noise of ,
l indeterminate origin. Recordings of the noise were sent to a vendor.
'
who supplied some possible sources, but was unable to definitely
pinpoint the cause.
1
The licensee has replaced the associated thermal sleeve and performed >
some extensive modifications to the piping, during the outage, to
address other issues. In addition, multiple accelerometers have been
installed on the makeup piping to monitor the noise. Since the restart,
the noise has not been present.
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ . _ _ _ _
62
c. .C_pnclusions
This phenomenon has not repeated following restart of the unit. The
licensee has identified that there was no physical impact caused by this
noise. This item is closed.
E8.23 (Closed) IFI 50-302/97-17-05: Resolution of Imoroved Technical
Soecification Setooint Proaram Deficiencies Prior to Entry Into Mode _4
a. Insoection Scoce (92903)
The inspector reviewed the licensee actions to resolve outstanding
issues with technical specification setpoint program improvements.
b. Observations and Findinas
At the conciusion of Inspection Report 97-17. the licensee had two
outstanding issues to resolve the technical specification setpoint
improvement program. At that time, the licensee had not completed the
field installation for some of the setpoint loop uncertainty
calculations and the licensee had not completed the Alarm Response
Procedures. Surveillance Procedures, and Plant Operating Procedures.
The inspector reviewed the identified procedures which had not been
updated and determined that a number still had not been updated
following completion of calculation upgrades. The inspector questioned
the engineering staff and determined that they were not tracking the
individual procedures. When questioned on January 16. 1998, the
licensee implemented a review of the outstanding procedures to verify
their status. Considering that the unit was approaching mode ascension,
this lack of follow-up until questioned by the inspector demonstrates a l
weakness in maintaining control of outstanding issues. l
The licensee identified that in a number of cases, the revised
calculation did not im)act the set points listed in the procedures. In
addition, procedures tlat were required to be revised were verified t-
be completed prior to mode ascension. The inspector verified the i
results of the licensee review and identified no discrepancies. l
c. Conclusions
During review of an open restart it. sue involving im)lementing setpoints,
the NRC noted that the licensee had not completed tle required procedure
changes following the calculation upgrades and was not tracking the
individual procedures until questioned by an inspector. This was
considered poor tracking of necessary restart restrictions (Section
E8.23).
E8.24 (Closgci) LER 50-302/97-14-00: Reactor Buildina Penetrations Do Not Meet
. Code Reauirements - Outside Desian Basis (FPC Restart Issue OP-16A)
. _ . ..
- - _ _ _ _ _ _ _ _- __- _ ____ - _ - .
.. .. ..
. .. . .
63
(Closed) LER 50-302/97-37-00: Containment Intecrity Cannot Be Proven
Followino Calibration of Buildino Soray Pressure Switches
a. Insoection Scooe (92903)
The inspector reviewed the licensee's closure documentation for their
Restart Issue OP-16A which encompassed the corrective actions for the
above items. The inspector verified installation of new components by
plant walkdowns and MAR review and verified new procedures were
deveioped.
b. Observations and Findinos
Both of these items were identified by the licensee during extent of ,
condition reviews for another of their restart issues involving
containment penetrations. They determined that several penetrations
were not designed correctly, were improperly aligned for Integrated :
Containment Leak Rate Testing done for 10 CFR 50 Appendix J I
requirements, and that the pressure switches (PS) for containment
atmospheric aressure utilized instrument air as one of the required two
containment )oundaries. This was inappropriate since instrument air is
not safety-related or seismically designed. These were reported under
the first LER. Subsequent reviews revealed that previous testing of the i
containment PS involved removal and replac6nent of the PS to support j
testing in the shop. This removal constituted a containment breach that i
was not tested after the PS was replaced and not factored into the l
containment leak ' rate test program. This was reported under the second '
LER. They consolidated their corrective actions under Restart Issue OP- l
16A. They revised the classification or upgraded the ratings of piping j
to resolve the design discrepancies. The inspector reviewed this '
effort. noted that it did not involve any modification to the plant. and
did not identify any discrepancies. To address the impact on Appendix J
testing, they performed a local leak rate test on the penetrations in
the proper configuration which entailed venting and draining the systems
to ensure they were exposed to the maximum potential differential
pressure. They factored the results of these tests into the previous
Integrated Leak Rate Test (ILRT) results and verified they had been
within their acceptance criteria for containment leakage. The inspector
reviewed the results of this effort as documented in FPC's letter
3F0897-11 to the NRC dated August 12. 1997, and did not identify any
discrepancies. To address the physical system design problems with the
containment PS they implemented MAR 97-07-04-01. Containment Instrument
i
Sense Line Penetration Upgrade. This modification upgraded the pressure
I sensing lines to ensure instrument air was not relied upon as a
containment boundary and added test and boundary valves to allow in
place testing of the PS. The inspector verified the changes were
implemented in the field and were reflected in procedure changes. The
inspector discussed all of the changes with the containment penetration
system engineer and considered them fully resolved. In the course of
the inspector's reviews. it was noted that tracking of MAR open items
and required procedure changes was difficult. Details of these
observations are further discussed in section E1.2.
_ _ - _ _ _ _ _
64
-
c. Conclusions.
The inspector concluded the licensee's actions were adequate to resolve
both of these open items. Although these items are noncompliances with
regulatory requirements, for the reasons discussed in Inspection Report
50-302/97-211 the licensee meets the criteria for enforcement discretion
per Section .II.B.2,of the NRC Enforcement Policy as described in NUREG-
1600. Consequently these items are closed and are identified as further
examples of Non-cited Violation NCV 50-302/97-21-01. Examples of-
Noncompliances in Design Control. 50.59 Evaluations. Procedure Adequacy.
Reportability, and Corrective Actions That Are Subject to Enforcement
Discretion.
~
The' inspector assessed the licensee's performance, with respect to this
restart-related issue, in the five NRC continuing areas of concern:
- Management Oversight - Good
. Engineering Effectiveness - Adequate
e Knowledge of the Design Basis - Good
e. Compliance with Regulations - Good
. Operator Performance - N/A
E8.25 (Closed) IFI 50-302/94-18-09: Review f eriodic Verification Plans - Motor
coerated Valves I
l
The recommendation to review periodically the verification of design
basis capability of safety related motor operated valves has been .
l
included as a required response to Generic Letter (GL) 96-05. Further l
NRC assessment of the licensee's periodic verification will be addressed
in regard to this generic letter. This-item is closed.
IV Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
R1 1 Radiolocical Protection General Emoloyee Trainina (83750)
Title 10 CFR Part 19.12 requires in part. all individuals who in the
course of employment are likely to receive in a year an occupational
- dose in excess of 100 mrem be instructed on radiation protection
measures.
FPC's Radiation Safety Procedure (RSP)-101 Basic Radiological Safety
Information and Instructions for Radiation Workers. Revision 21. dated I
January 30. 1996, provided radiological safety information relevant to j
all personnel classified as radiation workers at Crystal River Unit 3. '
The licensee utilizes computer based training to instruct workers on the
licensee's radiation protection program requirements, measures, and
procedures. The licensee supplements the computer based training with a
walk-through of the Radiation Control Area (RCA) which permits the
student to see implementation of those requirements. Since the computer
based training did not answer a student's specific questions or concerns
.
.
-
_ _ _ - _ _ -
__
65
the walk-through makes available a person that can answer specific
questions a student may have about the licensee's radiation protection
program and procedures. As such the walk-through is a very important
component in the licensee's radiation worker general employee training
program. Section 4.13 of RSP-101, described the process for initiating
and handling Radiological Practical Factors Sign-off sheets that were
used to document the practical factor walkthroughs.
As documented in Inspection Report 50-302/96-20 issued February 5, 1997,
licensee personnel reported a contractor had inappropriately certified a
Radiological Practical Factors Sign-Off training record. On December
20. 1996, a contractor certified that he had taken another employee into
.the RCA for a practical factors walk-through as required by licensee
procedures. Personnel in the Radiation Protection staff checked the RCA
access computer records and determined that the employee had not been in
.the RCA since December 5. 1996, and could not have completed the walk-
through training session.
NRC's investigation substantiated that the contract employee
inappropriately certified a trainirg record. A synopsis of the NRC
investigation is provided in the Attachment to this inspection report. '
Failure to complete the required practical factor walk-through as
required by the licensee's procedures was identified as a violation of
regulatory requirements. Consistent with Section VII.B.1 of the NRC
Enforcement Policy, this non-repetitive, licensee identified and
corrected violation is being treated as a Non-Cited Violation, NCV 50-
302/98-01-09. Failure to Perform Radiation Protection General Employee
Training Walk-Through In the RCA.
The licensee terminated the contractor. The licensee reviewed the
completed documentation that the individual had previously completed on
other workers and found no additional discrepancies.
V. Manaoement Meetinas
,
X1 - Exit Meeting Summary
The inspection scope and findings were summarized on February 6,1998.
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
X3 Management Meeting Summary
X3.1 On January 12, 1998. FPC Senior Management met with the NRC in
Rockville. Maryland. The purpose of the meeting was twofold: 1) a FPC
presentation that the " extent of condition" issues of the Confirmatory
Action Letter'had been adequately addressed and 2) present the FPC
" Integrated Assessment" of the 1997 outage activities. NRC management
concluded that the presentation and discussion answered all open
questions they had regarding CAL Items 2 & 3. A separate meeting
summary was issued on February 2, 1998.
66
X3.2 On January 27, 1998. Commissioner Greta Dicus, accompanied by Terence
Chan from NRC HQ. visited the CR3 site for an overview presentation by
. licensee management along with a plant tour.
67
PARTIAL LIST OF PERSONS CONTACTED
Licensees
R. Anderson, Senior Vice President, Energy Supply
J..Baumstark. Director, Quality Programs
S. Bernhoft, Manager. Nuclear Licensing
J. Cowan, Vice President, Nuclear Operations
R. Davis, Assistant Plant Director. Operations and Chemistry
R. Grazio. Director, Nuclear Regulatory Affairs
G, Halnon. Assistant Plant Director. Nuclear Safety
B. Hickle. Director, Restart
J. Holden, Site Director. Nuclear Operations
M. Marano, Director Nuclear Site & Business Support
C. Pardee. Director, Nuclear Plant Operations
W. Pike, Manager Nuclear Regulatory Compliance
'
M. Rencheck Director, Nuclear Engineering
M. Schiavoni. Assistant Plant Director, Maintenance
T. Taylor Director, Nuclear Operations Trainim
NRC
'
P. Fillion Reactor Inspector, Region II (January 5 - 9. 1998)
R. Gibbs, Resident Inspector. North Anna (February 2 - 6, 1998)
J. Jaudon. Director., Division of Reactor Safety, Region II (January 21,
February 3 - 4, 1998)
l C. Julian, Technical Assistant. Region II (February 2 - 6, 1998)
L. Reyes, Regional Administrator, Region II (January 27. 1998)
'
- K. O'Donohue. Resident Inspector, Vogtle (February 2 - 6, 1998)
-
l W. Rogers. Senior Reactor Analyst, Region II (January 21, 1998)
l R. Schin. Reactor Inspector, Region II (January 5 - 9 January 26 -
February 6, 1998)
'
M. Thomas. Reactor Inspector. Region II (January 5 - 9, 1998)
L. Wert. Senior Resident Ins)ector, Browns Ferry (February 2 - 6. 1998)
J. York. Reactor Inspector, Region II (January 5 - 9-, January 22 - 23.
January 28 - 30, 1998)
j INSPECTION PROCEDURES USED
t
IP 37550: Engineering
IP 37551: Onsite Engineering
, IP 40500: Effectiveness of Li isee Controls in Identifying. Resolving and
Preventing Problem.
IP 61726: Surveillance Observi :ons
IP 62707: Conduct of Maintenance
IP 71707: Plant Operations
IP 71715: Sustained Control Room and Plant Observation
IP 83750: Occupational Radiation Exposure
IP 92901: Followup - Operations
IP 92903: Followup - Engineering
IP 93802: Operational. Safety Team Inspection
67
PARTIAL LIST OF PERSONS CONTACTED-
Licensees
R,' Anderson, Senior Vice President Energy Supply
.J, Baumstark Director, Quality Psograms
S. Bernhoft, Manager, Nuclear Licensing
J, Cowan,:Vice President Nuclear 03erations
1 R, Davis, Assistant Plant Director, Operations and Chemistry
R. Grazio. Director. Nuclear Regulatory Affairs
~G. Halnon, Assistant Plant Director, Nuclear Safety
B. Hickle, Director, Restart
-J. Holden. Site Director, Nuclear Operations-
-M, Marano,' Director, Nuclear Site & Business Support
- C, Pardee Director Nuclear Plant Operations
W.~ Pike, Manager, Nuclear Regulatory Compliance
M. Rencheck, Director, Nuclear Engineering
M, Schiavoni, Assistant Plant Director, Maintenance
T, Taylor. Director, Nuclear Operations Training
E
P. Fillion. Reactor Inspector, Region II (January 5 - 9, 1998) i
.R. Gibbs, Resident Inspector, North Anna (February 2 - 6, 1998)
J. Jaudon, Director, Division of Reactor Safety, Region II (January 21.
February-3 - 4, 1998)
C. Julian, Technical Assistant, Region II (February 2 - 6. 1998)'
- L. Reyes, Regional Administrator, Region II (January 27, 1998)
K, O'Donohue, Resident Inspector, Vogtle (February 2 - 6, 1998)
W. Rogers, Senior Reactor Analyst, Region II (January 21, 1998)
R. Schin, Reactor Inspector, Region II (January 5 - 9. January 26
_
-
February 6. 1998)
-M. Thomas. Reactor Inspector, Region II (January 5 - 9, 1998)
.L. Wert, Senior Resident Ins)ector, Browns Ferry (February 2 - 6, 1998)
J. York, Reactor Inspector. Region II (January 5 - 9. January 22 - 23,
,
l January 28 - 30, 1998)
INSPECTION PROCEDURES USED
IP 37550: Engineering 1
- IP 37551: Onsite Engineering i
L
'
IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving and- i
Preventing Problems I
-IP 61726: Surveillance Observations !
IP 62707: Conduct of Maintenance !
IP!71707: Plant Operations
L IP 71715: Sustained Control Room and Plant Observation ;
'
IP 83750: Occupational Radiation Exposure
IP 92901: Followup .0perations
IP 92903: Followup - Engineering
IP 93802: Operational Safety Team Inspection
!
!
l
.
68
ITEMS OPENED, CLOSED, AND DISCUSSED
92RDid
lyng Item Number . Status Descriotion and Reference
.VIO ..50-302/98-01-01 Open Closure of Electrical Linkages While
Under a Red Tag Clearance (Secticq
01.2).
VIO 50-302/98-01-02 Open- Failure to Post Documents as
Required by 10 CFR 19.11 (Section
01.4).
NCV 50-302/98-01-03 Closed Failure to Follow OP-404. Resulting
in the Draining of Reactor Coolant
Inventory to the Auxiliary Building
Sump (Section 04.2).
NCV 50-302/98-01-04 Closed Late Submittal of ITS Bases Changes
(Section 08.2).
NCV 50-302/98-01-05 Closed Failure to Promptly Correct the
Seismic Qualification of NuPro
Valves (Section E1.3)-.
VIO 50-302/98-01-06 Open Lack of Emergency Lights for
0)eration of Appendix R Safe
Slutdown Equipment (Section E8.2).
VIO 50-302/98-01-07 Open 500 KV Backfeed Not a Qualified
l
t
Source of Offsite Power (Section
E8.16).
VIO 50-302/98-01-08 Open Inadequate Procedures for Use of 500
KV Backfeed (Section E8.16).
NCV 50-302/98-01-09 Closed Failure to Perform Radiation
Protection General Employee Training
Walk-Through in the RCA (Section
R1.1).
Closed
T_Ygg Item Number Status Descriotion and Reference
NCV 50-302/98-01-03 Closed Failure to Follow OP-404. Resulting
in the Draining of Reactor Coolant
Inventory to the Auxiliary Building
Sump (Section 04.2)..
69
LER 50-302/96-13-00 Closed Failure to Use Self-Checking by
(terator Leads to Unplanned
Actuation of Engineered Safeguards
Pump (Section 08.1).
'IFI 50-302/97-11-04 Closed Corrective Actions For Approximately
4000 Precursor Cards Not Tracked To
Completion (Section 08.2).
NCV -50-302/98-01-04 Closed Late Submittal of ITS Bases Changes
(Section 08.2).
IFI ~50-302/97-14-01 Closed Review of Operational Procedures
,
,
Prior to Restart (Section 08.3).
NCV 50-302/98-01-05 Closed Failure to Promptly Correct the
seismic Qualification of NuPro
Valves (Section E1.3).
URI 50-302/95-02-02 Closed Control Room Habitability Envelope
Leakage (Section E8.1).
VIO 50-302/97-02-03 Closed Adequacy of Procedures to Take the
P1 ant froni Hot' Standby to Cold
<
Shutdown from Outside the Control
i
Room (Section E8.2).
LER 50-302/97-41-00 Closed Control Complex Chiller may be
Rendered Unavailable due to Design
Error (Section E8.8).
L
LER 50-302/96-05-01 Closed Inadequate Failure Modes
50-302/96-05-02 Review Creates Possibility of
Cooling Water Flow Outside of Design
j Limits (Section E8.13).
LER 50-302/96-23-00 Closed Personnel Error Leads to Missed
50-302/96-23-01 Surveillance Resulting in Violation
of TS (Section E8.14).
VIO EA 97-330. Closed Failure to Update the FSAR to
VIO B (01023) Include Added EDG Trips (Section
E8.15).
'URI 50-302/96-201-06 Closed Preferred Offsite Electrical Power
Source With Plant Shut Down (500 KV
Switchyard) is Not Qualified
(Section E8.16).
LER 50-302/97-45-00 Closed Containment Isolation Valves Not
Seismically Qualified Due to an
Installation Error-(Section E8.17).
70
LER 50-302/95-23-01- Closed Inconsistent Design Assumptions
50-302/95-23-02 Cause Building Spray. Pump Flowrate
Concerns Resulting in Operation
Outside the Desig6 Basis (Section
E8.18).
,
IFI 50-302/95-02-05 Closed Resonance Noise in Vicinity of MUV-
25 (Section E8.22).
IFI 50-302/97-17-05 Closed Resolution of Improved Technical
Specification Setpoint Program
Deficiencies Prior to Entry Into
Mode 4 (Section E8.23).
LER 50-302/97-14-00 Closed Reactor Building Penetrations Do Not
Meet Code Requirements - Outside
Design Basis (Section E8.24).
LER 50-302/97-37-00 Closed Containment Integrity Cannot Be
Proven Following Calibration of
Building Spray Pressure Switches and
Transmitters (Section E8.24).
IFI 50-302/94-18-09 Closed Review Periodic Verification Plans -
Motor Operated Valves (Section
E8.25).
NCV 50-302/98-01-09 Closed Failure to Perform Radiation
Protectiori Gercral Employee Training
Walk-Through in the RCA (Section
Ri.1).
Discussed
Typ.g Item Number S_ta_tn Descriotion and Reference-
,
VIO 50-302/97-16-03 Open Failure to Design and Install
l .- Radioactive Waste Disposal System
Piping as Described in the FSAR
,
(Section E8.3).
!
l
LER 50-302/97-38-00 Open An Engineering Oversigh't Resulted in
Operation Outside of the Design
Basis-for the Waste Disposal System
(Section E8.3).
-VIO - 50-302/97-16-04 Open Failure to Follow Procedure CP-111
by not Performing a 10 CFR 50.59-
-
Safety Evaluation Within 90 Days
After Identification of a Non-
1
)
71
conforming Condition Which
Conflicted with the FSAR Description I
(Section E8.4).
VIO 50-302/97-16-05 Open Compliance with the ODCM
Surveillance Requirements for the 1
WGDTs (Section E8.5).
LER 50-302/97-43-00 Open Control Complex Chiller Motor Set
Points Below Full Load Ampere
Setting (Section E8.6).
)
LER 50-302/97-25-01 Open Service Water / Raw Water Temperature
Calculation Contains Non
Conservative Assumptions (Section
E8.7).
VIO EA 96-365. Open Error in Design Calculations
VIO B (02013) for SW System Heat Loads-(Section
E8.7).
""V 50-302/97-21-01 Closed Examples of Noncompliance in Design
Control. 50.59 Evaluations.
Procedure Adequacy. Reportability.
and Corrective Actions That Are
Subject to Enforcement Discretion
(Sections E8.8. E8.17. E8.24).
VIO ;50-302/96-01-06 Open Failure to Correctly Translate
Design Basis of SW System into
Procedures. Drawings, and
Instructions'(Section E8.13).
VIO 50-302/96-15-01 Open Failure to Perform a Requi-ad TS
Surveillance for the Remote Shutdown
Panel (Section E8.14).
LER 50-3J2/97-13-00 Open- Functional Testing of EDG-1A Room
Temperature May Exceed 120 f
(Section E8.20).
LER 50-'302/97-19-00 Open Elevated dug Supply Air Temperature
l 50-302/97-19-01 Due to EDG Radiator Discharge Air
'
Recirculation Effect'(Section
E8.20).
L
LER 50-302/97-27-00 Open Failure to Add Antifreeze to the
Diesel Generator Coolant Radiators
May Render EDG Inoperable During
Subfreezing Temperatures (Section
E8.20).
,
. .
. . _ . .
_ - _ _ _ - _ - _ _ _ _ _ _ _ _ _ _
.
. .. . . ..
k
72
LIST OF ACRONYMS USED
AI - Administrative Instruction
A0 - Auxiliary Operator
Abnormal Procedures
'
.AP
CARB .- Corrective Action Review Board
CDIP.- - Configuration Document Integration Project
CFR- -. Code of Federal. Regulations
CP- - Compliance Procedure
CRD - Control Rod Drive
CREVS - Control Room Emergency Ventilation System
CR3 - Crystal River Unit 3
DH - Decay Heat
DHP- - Decay Heat. Pump
DHV - Decay Heat Valve-
DNP0 - Director. Nuclear P1 ant Operations
DR - Deficiency Report
DRB - Design Review Board
EA Enforcement Action
ECP - Estimated Critical Position
EDBD --Enhanced Design Basis Document
EDG - Emergency Diesel Generator
E0P - Emergency Operating Procedure
ES - Engineered Safeguards
ESAS - Engineered Safeguards Actuation Signal
FCN - Field Change Notice i
FMEA-' - Failure Modes and Effc.cs Analysis
- FPC - Florida Power Corporation
FSAR - Final Safety Analysis Report
FT - Flow Transmitter
GLL - Generic Letter 1
HP. - Health Physics
HPI - High Pressure Injection
I&C - Instrumentation and Control
IFI- - Inspection Followup Item
ILRT - Integrated Leak Rate Test
IOC - Interoffice Correspondence )
LIR - NRC Inspection Report )
ITS - Improved Technical Specifications
IWCC - Immediate Working Copy Change
'JC0 - Justification for Continued Operation
KV - Kilovolt
Kw - Kilowatts
LAR - Licensing Amendment Request
LC0 - Limiting Condition for Operation
LER - Licensee Event Report
LLRT - Local Leak Rate Test
LOCA - Loss of Coolant Accident
MAR - Modification Approval Record
MCC - Motor Control Center
MD - Motor Driven
_____- _ _ _ _ _ _ _ - _ _ _ _ . /
[
( 73
< MUHE - Makeup and Purification Heat Exchanger
MVP - Makeup Pum)
MUT - Makeup Tanc
MUV - Make-up Valve
.
MWST - Miscellaneous Waste Storage Tank-
NCV - Non-cited Violation.
- NEP - Nuclear. Engineering Procedure
l -N0E- Nuclear Operations and Engineering
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
i NRR - Office of Nuclear Reactor Regulation
NSAT - Nuclear Safety Assessment Team
l NSM- - Nuclear Shift Manager
' NSS - Nuclear Shift Supervisor
NUPOST - Nuclear Operations Procedure Observations and Suggestions Tracking
ODCM - Offsite Dose Calculation Manual
i
01 - Operating Instruction
- OP - Operating Procedure
OSB - Operator Study Book
f r
OSTI - Operational Safety Team Inspection
PC - Precursor Card
PRC - Plant Review Committee
l PS- - Pressure Switch
!
PT- - Periodic Test-
RB - Reactor Building
RBCU - Retetor Building Cooling Unit
RCA - Radiologically Controlled Area
RCBT - Reactor Coolant-Bleed Tank
RCDT. - Reactor Coolant Drain Tank
l RCP - Reactor Coolant Pump
L RCS- - Reactor Coolant System l
REA - Request for Engineering Assistance i
. RNO- - Response Not Obtained 1
-
R0 - - Reactor Operator i
RP&C- - Radiological Protection and Chemistry ;
RSP- - Radiation Safety Procedure
RW. - Raw Water- 1
L SBLOCA.- Small Break Loss of Coolant Accident
- SER - NRC Safety Evaluation Report ;
l-
SM - Shift Manager
SMC - System Maintenance Crew
- Surveillance Procedure
'
- SP j
- SR - Surveillance Requirement :
SR0 - Senior. Reactor Operator !
SRST - S)ent Resin Storage Tank
STI S1 ort Term Instruction
TC - Temporary Change
.
_
f 74
TDBD - Topical Design Basis Document
TMAR - Tem)orary Modification Approval Record
TS - Tec1nical Specification
TSC - Technical Support Center
URI - Unresolved Item
US0 - Unreviewed Safety Question
US00 - Unreviewed Safety Question Determination
VIO - Violation
WDS - Waste Disposal System
WGDT - Waste Gas Decay Tank
l
l
.
-
t
.
i SYN 0PSIS
i
'
The U.S. Nuclear Regulatory Commission. Region II, Office of Investigations
initiated this investigation on April 3,1997, to determine if a contractor
employee inaparopriately certified that a practical factors walkthrough had
occurred in tie Radiation Control Area, when it had not.
The evidence developed during this investigation substantiated that a Florida
Power Corporation Crystal River Nuclear Plant contractor employee --
l
'inapproprictely certified a training record.'yet it was not deliberate'6r
ir.tentional .
i
I
.
i
o r
)
.
d
.
o
i
~
NOT ICR PUOLIC OISCLOSURE L'IT"OUT APPROVAL CT T9E '
IIELO CITICE DIRECTOR, CITICE CI IN" 5TIGATIONS, RECION II
Case No. 2 97-008 1 Approved for release on <
March 3, 1998
Enclosure 3