ML20203F563
| ML20203F563 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 02/23/1998 |
| From: | Jaudon J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20203F553 | List: |
| References | |
| 50-302-97-12, NUDOCS 9803020003 | |
| Download: ML20203F563 (43) | |
See also: IR 05000302/1997012
Text
U. S. NUCLEAR REGULATORY COMMISSION
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REGION 11
EMERGENCY OPERATING PROCEDURES TEAM INSPECTION
Docket No.: 50 302
License No.: DPR 72
Report No.: 50-302/97-12
Licensee: Florida Power Corporation
Facility: Crystal River 3 Nuclear Station
Location: 15760 West Power Line Street
Crystal . R1ver, F1orida
Dates: October 20 through 24. 1997. December 8 through 12, 1997,
and January 5 through 9, 1998
Team Leader: W. Rogers. Sr. Reactor Analyst. Division of Reactor Safety
Inspectors: J. Bartley. Resident inspector. Division of Reactor Projects
G. Galletti. Human Factors Specialist. Office of Nuclear
Reactor Regulation (NRR)
P. Harmon. Sr. React Inspector. Division of Reactor Safety
L. Me 1 . Re r Inspector. Division of Reactor Safety
Approved by: 4h 13[ff
.( Jhudgn. Direhor~. Date Signed
Division of Reactor Safety
~
9003020003 980223
PDR ADOCK 05000302
G PM Enclosure 2
EXECUTIVE SUMMARY
Crystal River Nuclear Plant. Unit 3
NRC Inspection Report 50 302/97-12
Five headquarters and regional inspectors used a sample approach to assess the
adequacy of the emergency operating procedures (EOPs) development process.
The team observed operating crews respond to numerous simulated emergency
conditions developed by the team to test specific sections of the E0Ps. The
inspection
Procedures.guidancewasInspectionProcedure42001."EmergencyOperating
Three weeks of on-site inspection were performed with draft E0Ps
and supporting documents inspected during the first on-site week. Plant
Review Committee approved E0Ps and supporting documents were used during the
other two on-site weeks.
Operatiom
. At the beginning of the inspection. the licensee had deviated from the
Technical Bases Document (TBD) numerous times without providing any
technical justification or adequate technical justification for the
deviations. Following NRC identification, the licensee upgraded the
technical justification documents and/or revised the E0Ps. After the
upgrade, some of the justifications were still not adequate. These
actions require additional justification or revision of the E0Ps to
ensure the mitigation strategy is accomplished. In addition. there were
other less significant actions differing from the TBD. Also. TBD
actions to be accomplished by the TSC were not incorporated into
procedures. The examples of inadequate justifications lack of
technical justifications, limited technical justifications and procedure
omissions were indicative of numerous E0P development process
weaknesses. A number of thes examples were part of a violation (section
03.1).
. At the beginning of the inspection the licensee's in-plant portion of
the verification and validation (V&V) process, which was being performed
on the draft E0Ps was insufficient. There were no specific concerns
regarding the control room portion. In response to the team's
perspectives. the licensee provided additional guidance for the in-plant
V&V. and the team noted improvements. However, even with the
improvements, there were other specific and general deficiencies
reflecting inadequacies in the in-plant V&V process. Also, some of the
team's original concerns were not adequately addressed partially due to
inadequate correction actions to a problem previously identified by the
licence associated with in-)lant o)erator accessibility. The disparity
between licensed operators )eing a)le to perform control room E0P
actions and non-licensed / support personnel not always being able to
perform in-plant E0P actions was consistent with the way in which the
V&V process was established and implemented. Consequently, the actions
directed by the E0Ps within tne control room could always be performed
but, numerous in-plant actions either could not be performed due to the
lack of support personnel. the lack of properly stagged equipment,
technically incorrect procedure steps, not incorporating the actions
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into procedures or the radiological consequences of performing the
actions had not been assessed. A number of these inadequacies were part
of a violation (section 03.2).
. The E0P Writer's Guide was comprehensive and adequately implemented in
the construction of the E0Ps. This contributed to operators rarely
having trouble reading or understanding the E0P steps during the
simulator scenarios (section 03.3).
. Following revisien, the licensee's E0P User's Guide was acceptable
(section 03.4).
. The maintenance and revision procedure was adequate. The scope of the
NRC review did not include set point control (section 03.5).
. The operating crews were capable of mitigal.ing the transients presented
by the team. However, there were some examples of performance
inconsistent with an E0P step. licensee management expectations or the
licensee's administrative guidance. These performance problems were
being dispositioned consistent with their significa.nce (section 04).
. The E0P//,P training program for licensed operators was adequate. There
was a program weakness of not training secondary plant operators on
resetting the emergency feedwater turbine's over speed trip. The
licensee provided corrective actions consistent with the significance of
the weakness (section 05).
Maintenance
. The work control process did not consider that work could inhibit access
to in-plant E0P action locations. The licensee was formulating
con active actions to this weakness (section M3.1).
. The licensee's program for implementing Technical Specification 5.6.2.4
was not adequate. but the actual external leakage did not exceed post-
accident dose consequences requirements. The licensee was taking
appropriate corrective actions to correct this non-cited violation.
(section M3.2)
. The technical content of the periodic inventory controls for in plant
E0P equipment was adequate (section M3.3).
Enaineerina
. Generally, calculations issued prior to 1995 contained numerous errors.
Occasionally, the calculations did not contain enough information to
enable a person. who was technically qualified in the subject to review
and understand the analyses and verify the adequacy of the results
without recourse to the originator. This was a violation. Prior to the
team's arrival, the corrective actions to known calculational
inadequacies had not extended to the E0P set point calculations which
was an example of a violation. Although a small sample size was
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reviewed by the team the calculations issued in 1997 to support E0P set
points were far better (section E1.1).
. During at least two time periods after the operating 11 cense was
granted. there was no procedural guidance to use the LPI crossover line
with flow split between the two LPI lines to mitigate the consequences
of a LOCA. Also, a recent change to the USAR regarding the LPI
crossover line method of long term core cooling was inconsistent with
applicable topical reports. The NRC will further review these
unresolved matters (section E1.2).
. The MUPs used for ECCS high pressure injection were not purchased to
specifications commensurate to the duty to be incurred during a
postulated post-accident LOCA. This was a violation. (section E1.3)
. The EDG air start circuitry was properly designed to prevent continued
application of startirg air to an EDG until depletion of the staring
air, and appropriate operator training had been provided on how to
respond to a tripped EXi (section El.4).
. The LPI injection valves were maintained normally closed, consistent
with the FSAR. However, in a letter dated 1/13/76 the licensee
committed to maintain the valves normally open and update the FSAR
accordingly, Those actions were never accomplished. The NRC will
further review this unresolved matter (section E1.5).
. The licensee identified a wiring error in the control room heating and
ventilation systern. T.e license was taking appropriate actions to
correct this non-cited violation. (section E8.1)
- .- . . _- . - . . . -- . . - .
,
Report Details
- Summary of Plant Status
Crystal River Unit 3 was shutdown with Reactor Coclant System temperature
below 200* Fahrenheit during the inspection period.
Introduction
The primary objective of this inspection was to assess the adequacy of the
process used to develop and implement emergency o>erating procedures (EOPs).
The team used a sampling approach to evaluate teclnical content,
administrative controls, verification and validation and, engineering
calculations and analyses supporting the E0Ps.
I. Operations
03 Operations Procedures and Documentation
03.1 Conformance to the Technical Bases Document (TBD)
a. Insoection Scoce (42001)
The team reviewed substantial portions of the E0Ps against the
procedural guidelines of the B&W Owners' Group E0P TBD (74-1152414 Rev.
8) and two owners' group approved TBD changes which will be incorporated
into the next revision. W1ere deviations were noted. the team evaluated
the licensee's technical justification documents (TBD - E0P Cross Step-
Document & E0P - TBD Cross Step Document) to verify that deviations from
the TBD such as additions, omissions, and sequence changes were
technically justified and did not affect the mitigation strategy.
During the October onsite inspection, the team reviewed the draft E0Ps
scheduled for PRC approval in November, During the December onsite
inspection, the team reviewed the PRC conditionally approved E0Ps.
During the January onsite inspection. the team continued to review
select (PRC) conditionally ap3 roved E0Ps and, due to previous NRC team
findings, revisions to the E03s.
Due to the numerous design changes being implemented and outstanding
Technical Specification requests yet to be approved by the NRC Office of
Nuclear Reactor Regulation (NRR). the team based the review, assuming
that License Amendment Requests (LAR) 210 (dated June 14, 1997). (LAR)
214 (dated October 31. 1997) and (LAR) 218 (dated September 9, 1997).
would be acceptable to NRR without deviation. The team did not review
the technical adequacy of the E0P actions dealing with boron
precipitation control since the adequacy of tk. licensee actions in this
area was being reviewed by NRR.
b. Wservations and Findinas
1. During the October onsite inspection, the team determined that the
licensee deviated from the TBD guidelines numerous times. The
omi,sions and additions were typically identified in the desiation
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documents. However, most of the justifications were not adequate.
Also, the licensee did not identify any step sequence changes as
deviations or confirm that the sequence deviations were non-
consequential with regard to the mitigation strategy.
(a) Specific examples of inadequately justified deviations were:
. TBD III.B. Lack of Adequate Subcooling Margin, step
8.2.b provided direction to maintain OTSG tube to
shell temperature differentials within limits. The
licensee omitted this step and documented its omission
in the deviation document. However, the justification
was very general and did not provide adequate details
to assess the deviation.
. TBD. SBLOCA/SBLOCA Cooldown, step 17.4 directed
establishing auxiliary spray, if desired. The
licensee omitted this step and justified its omission
solely on it being an optional action.
. TBD. SBLOCA/SBLOCA Cooldown. step 8.0. directed
verifying flow in each LPl line > [ min flow). The
E0Ps stated to verify flow in any LPI line. TBD
Vo ume III stated the basis was to verify adequate LPI
.
flow for core cooling prior to transitioning to LBLOCA
CD. The licensee's justification discussed
identifying aressure below LPI pump head without
discussing w1 ether there was adequate core cooling.
. TBD. LBLOCA Cooldc,;n. ste) 1.2 directed opening the
LPI crosstie if only one _PI pump was available to
ensure injection through both lines The ECPs omitted
this step. The justification was that the motor
oaerated valves may or may not have power available
w1ich didn't addrese why the step could not be
accomplished or its impact on the mitigation strategy.
(b) Specific examples of deviations that wr.re not identified and
justified were:
. TbD lil.A. Immediate Actions and Vital System Status
Verification (VSSV). steps 2.3 and 2.4. directed that
adequate primary to secondary heat transfer be
attempted and to begin maximum boric acid addition if
reactor power was not decreasing when the reactor was
required to be tripped (i.e. an Anticipated Transient
Without a Scram (ATWS)). E0P-02. VSSV. did not
address primary to secondary heat transfer or
initiating boric acid addition until much later in the
procedure. Consequently. during a complete ATWS from
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90% reactor power simulator scenario, the operating
crew was not able to perform the TBD mitigation
strategy.
. TBD lli.B. Lack of Adequate Subcooling Margin. step
4.0. directed isolating possible RCS Leaks (4.1) and
verifying RB Noling (4.2). The licensee did not
direct isolating possible RCS leaks until step 3.17 of
E0P03.InadequateSubcoolingMargin. Verification of
RB Cooling was performed in step J.9. The sequence
deviation and impact on delaying corrective actions
was not identified in the deviation document.
. TBD lil.B. Lack of Adecuate Subcooling Margin, steps
1B.0 18.6. were movec to E0P-14. E0P Enclosures.
Enclosure 16. RCP Recovery, without technical
justification.
. The TBD periodically repeated critical checks and
procedural transitions. The licensee re) laced these
periodic checks with carryover steps witlout technical
justification.
. E0P 03. Inadequate Subcooling Margin. Steps 3.37 -
3.55. were imported from TBD SBLOCA Cooldown without
technical justification as to why the steps were not
contained in E0P-08. LOCA Cooldown.
. The following steps were sequenced differently in E0P-
07. Inadequate Core Cooling, than TBD lli.F.
Inadequate Core Cooling without justification.
TBD Sten E0'-07 Sten
_10.0 3.29
12.0 3.31
12.1 3.31
12.2 3.33/3.34
12.3 3.35
13.1 3.31
13.3 3.30
13.7 3.32
. The following steps were sequenced diffarently than
the SBLOCA/SBLOCA Cooldown TBD without justification.
TBD Sten LOP-07 Sten
2.1 3.10
2.2 3.25
4.1 3.15
4.2 3.32
_ _ _ _ _ _ _ _ - _ _ _
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5.0 3.20
6.0 3.14
7.0 3.36
2. Following NRC identification to the licensee of the generally goor
justifications from the TBD. the licensee began upgrading the BD
- Cross step documents and/or revising the E0Ps. Consequently,
the draft E0P 02 procedure was revised for responding to an ATh'S.
and TBD step 17.4 of SBLOCA/SBLOCA Cooldown. directing the
establishment of auxiliary spray, was added to E0P 08. LOCA
Cooldown. Also, in concert with the B&W Owners' Group, the TBJ
was changed to indicate that steps could be preformed out of
sequence provided the mitigation strategy was not compromised.
3. During the December onsite inspection the team identified
inadequacies and weaknesses in the upgraded TBD Cross step
documents.
(a) The inadequacies included:
. TBD. LBLOCA CD. step 3.0. directed securing HPI when
LPl flow of *x" (the minimum flow for adequate core
cooling derived by the licensee) amount existed for
greater than 20 minutes. TBD Volume 3 identified that
this v:as due to concerns of: 1) increasing radiation
levels in the auxiliary building iAB) during RB sump
retirc while in the piggyback mode. 2) pump failure.
and 3) possibly avoiding the complex evolution of
switching to the piggyback mode. The licensee had
removed this guidance and opted for long term
operation of the HPI pumps in piggyback mode. The
technical justification was not adequate in that it
did not address the above items of concern.
. TBD. LBLOCA CD. Step 1.2. directed opening the LPI
crosstie if only one LPI pump was available to allow
injection through both LPI lines. The licensee
omitted this guidance without adequate technical
justifitation since LPI operation in this manner was a
licensing basis requirement. FSAR. Chapter 6. Section
6.1.2.1.2 specifically stated that "the LPI System is
provided with a crossover line to permit one LPI
string flow of 3.000 gpm to be split equally. thus
providing a minimum of 1.500 gpm flow to both core
flooding injection nozzles simultaneouGy should a
core flooding line or one LPI pump fail." Also, the
B&W topical reports approved by the NRC verifying
licensee compliance to 10 CFR 50.46. Acceptance
criteria for emergency core cooling systems for light
water reactors, listed. ~one LPI pump operating with
crossover line valves open; flow split Detween the two
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LPI lines by the control valves." as one of three
required long term core cooling methods. Section El.2
of this report contains additional discussion of the
licensing pasis for this operation.
- TBD Section Ill.B. Lack of Adequate Subcooling Margin,
step 8.0 provided time critical guidance for starting
an emergency cooldown if HPl was not available.
Volume Ill of the TBD stated that for SBLOCAs where
HPI flow could not be established. " Plant cooldown
must start immediately upon a loss of mbcooling
margin in order to avoid severe core ( age." The
licensee added nine steps prior to the step which
initiated the emergency cooldown due to no HPl. The
justification for adding these steps did not address
delaying the cooldown. The team o) served that an
operations crew on the simulator, responding to a
total loss of HPl. took 29 minutes to commence the
emergency cooldown.
. Step 2.2.1 of E0P 02. Vital System Status
Verification, directed de-energizing the CRD system to
insert control rods if the reactor protection system
failed. Step 2.2.2 directed re energizing the CR0
buses by closing 4B0 VAC supply breakers. 3305 and
3312. There was no corresponding TBD section or step
for re-energizing the buses. and a technical
justification for inserting the step was not included
in the cross step document. Breaker 3312 was between
4160 VAC ES Bus 3B and the 480 VAC Plant Aux Bus. The
effects of re-closure of breaker 3312 on the 4160 VAC
ES Bus 3B had not been analyzed. During an ATVS
simulator scenario, the team observed an operator
momentarily open the 3312 breaker and then reclose it.
Subsequent analysis indicated that breaker 3312 must
be open for at least three seconds to assure that the
currently connected bus loads would not re-tri) the
bus on over current. Also, there was another areaker.
3222 (the supply breaker from the 4160 VAC ES Bus 3B).
in line with breaker 3312 and 480 VAC Plant Aux Bus.
Neither breakers. 3222 or 3312. had been tested under
these conditions.
By letters dated October 31. 1980 and December 17. 1982.
from D. Eisenhut (NRC) to all licensees of operating plants
and applicants for operating licenses and holders of
construction permits. the post-Three Mile Island (TM1)
requirements. NUREG-0737. " Clarification of TMl Action Plan
Requirements." and Supplement 1 to NUREG 0737. " Requirements
for Emergency Response Capability " were issued. NUREG-0737
criterion 1.C.l. " Guidance for the Evaluation and
..
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Development of Procedures for Transients and Accidents." I
- provided clarification regarding the requirements for i
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reanalysis of transients and accidents. Item 7 of
Supplement 1 to NUREG 0737. " Upgrade Emergency Operating
Procedures (E0Ps)" directed that licensees develop a
procedures generation package (PGP) which included a ,
,
description of the validation program for the E0Ps. !
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By letter dated March 25, 1983. Florida Power Corooration '
of NUREG 0737. Supplement 1.ponsecontained
The response to the I.C.1 a requiremen
. discussion of the upgraded E0P validation program which t
- stated. in part that the purpose of the validation program
.
was to demonstrate the usability of emergency procedures.
The instructions to operators were to be complete.
j understandable and, compatible with conditions. Licensee
- 3rocedure Al 402C AP and E0P Verification and Validation
)lan. enclosure 3. required differences between the
procedure and the TBD be documented and justified.
On February 21. 1984, the NRC issued an Order modifying the
Operating License which confirmed the licensee's
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implementation of I.C.1. These above examples of inadequate
technical
were examples justifiestions affecting
of violation . VIOthe miti50 302/97 12-01. gation strategy
" Inadequate Implementation of TM1 Action item E0P Order."
- Also, the significance and number of the examples, was
indicative of a weakness in the process for developing the
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E0Ps.
(b) In addition to the inadequacies, there were other actions
different from the TBD that were not fully justified in the
Cross step documents, but did not appear to affect the >
mitigation strategy. As an example, the licensee inserted
steps 3.4. 3.5. and 3.6 into E0P 05. Excessive Heat
Transfer, which were not part of the owners' group guidance.
This resulted in step 3.7 (which would have corresponded to
step 3.4 in the TBD) being moved to later in the E0P. The
only justification for this change was that step 3.7 was
placed where it was because " steps 3.4. 3.5, and 3.6 were
added to the procedure.' While this explanation may
account for how the step numbers changed, it provided no
technical justification for the change. The new steps
appeared minor in terms of effect (both mitigation strategy
and time delays). However, the licensee provided no
technical basis for this change. Other similar step
sequence changes were identified in this and other E0Ps. and
referred to the licensee. None of the changes appeared to
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. change the accideL., mitigation strategy or the timeliness of '
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procedur61 steps, but the lack of or limited technical
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justification and documentation was indicative of a weakness
- in the process for developing the E0Ps.
i
4. Also in December, during a review of PRC conditionally a> proved '
i- E0P 8. LOCA Cooldown, the team recognized that several TB) ste)
i actions were omitted from the E0Ps and were justified in the T3D-
- Cross step documents on the basis that the TSC would )rovide the
j guidance required to perform the actions. However, tie licensee ,
had not developed any TSC guidance to address the actions stated i
-
in the TBD and therefore the documentation to support the
i justification for deviation from the B&W guidance was incomplete.
Examples of the steps affected included: :
_ lBD !
- Step 2.2 Trip RCPs if running.
Step 6.2 Monitor and Control hydrogen concentration i
in RB in accordance with plant specific :
method.
!
Step 6.4 If sump is being diluted...
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a. check for and attempt to isolate
leaks into the RB 1
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b. If leaks into the RB are found and -
cannot be isolated. Then commence
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necessary to maintain adequate
Step 6.6 Maintain RB sump level within appropriate
<
high-low limits.
Step 6.7 If sump water level must be drained THEN
ensure radioactive water will be
appropriately stored.
I These inadequately technically justified actions are additional
examples of--violation VIO 50/302 97-12 01. ~1nadequate
j Implementation of TMl Action Item E0P Order.~
5. The team observed implementation of the revised E0P 02. VSSV. in -i
i response to an ATWS simulator scenario in December. The TBD
mitigation strategy'was accomplished.
j _. 6. During the January 98 onsite inspection, the team identified two
other actions that were not technically justified with respect to
the TBD. These actions were contained in E0P 06. SGTR. and were:
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- The time delay insertion of site specific steps 3.1, 3.2 and
3.3 between SGTR identification and determination that the
reactor was tripped. The additional steps were not in the
TBD. These additional actions impacted the timely attempts
to restore pressurizer level in step 3.5, which increased
the chances of manually tripping the reactor above the
secondary side steam pressure set points for the atmospheric
dump valves (ADVs) and main steam safety valves (MSSVs).
Opening these valves would increase the radiological dose to
t1e public since these are direct release pathways and
should be avoided. The team observed an o)erations crew on
the simulator responding to a SGTR in whic1 the crew did not
maximize makeu) (complete step 3.5) before manually tripping
the reactor a ligh power per step 3.6. Also, during another
SGTR c:enario in a previous week. the crew jumped ahead to
step J.5 to maximize makeup as soon as possible. The cross
step document indicated that the addition of site specific
steps 3.1, 3.2 and 3.3 were not consequential.
. The time delay possible in not isolating the EFWT steam
supply from the affected OTSG. If the affected OTSG's steam
is used to power the turbine driven EFW pump, the turbine's
exhaust would be a direct radiological release path. Step
3,3 of the TBD directed isolating all non essential steam
loads during a rapid power reduction prior to tripping the
reactor below the ADV and MSSV set points. The licensee did
not isolate the affected OTSG EFWf steam supply until step
3.45 or 3.46. The licensee did justify not isolating the
steam supply during the rapid power reduction since its
isolation could induce a system perturbation causing a
reactor tri? above the ADV and MSSV set points. However,
following t1e manual trip, the licensee did not technically
justify delaying the steam supply isolation. The team
observed an operations crew on the simulator responding to a
SGTR in which an hour elapsed before this action was done.
The licensee initiated PC-98-0151. based on the team's
observations.
These two inadequately technically justified actions are
additional examples of violation. VIO 50/302-97-12 01. " Inadequate
Implementation of TMI Action item E0P Order.".
c. Conclusions
At the beginning of the inspection. the licensee had deviated from the
TBD guidelines numerous times. The omissions and additions were
typically identified in the deviation documents. However, most of the
justifications were not adequate. Also, the licensee did not identify
any step sequence changes as deviations or confirm that the sequence
deviations were non consequential with regard to the mitigation
strategy. Following NRC identification of the generally poor
.-
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i justifications from the TBD the licensee upgraded the technical
. justification documents and/or revised the E0Ps. After the upgrade.
l some of the justifications were still not adequate to support deviating ,
~
from the TBD since the actions affected the TBD mitigation strategy.
- These actions require additional justification or revision of the E0Ps ;
. to ensure the mitigation strategy is accomplished. In addition to the
1 iradequacies there were other less significant actions differing from
) the TBD which did not appear to affect the mitigation strategy that were ;
'
not fully technically justified. Also, the licensee failed to ensure
that TBD actions to be accomplished by the TSC were incorported into
4
procedures. The examples of inadequate technical justifications lack
i of technical justifications, limited technical justifications and
, procedure omissions were indicative of numerous process weaknesses in '
,
developing the E0Ps a number of these examples were part of a violation.
! 03.2 Verification & Validation (V&V) Guidelines
a. Inspection Stone (42001)
P
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The team reviewed the licensee's V&V instruction (Verification and
Validation Plan Al 402C Rev, 4) to ensure that it adequately addressed
the issues associated with verifying the technical and humaa factors
adecuacy of the procedures and validated that the procedures could be
usec by the operators to mitigate transients and accidents. The team
reviewed a sample of the V&V records maintained as part of the E0P
development program. The team observed licensed and non licensed
operators respond to simulated emergercy conditions developed by the
team to test specific sections of the E0Ps. The evaluation of operator
actions included the ability of the operators to carry out those
designated actions, both inside and outside the control room. From
these direct observations the team could partially determine whether the
V&V instruction and its implementation was adequate. Also, the team
independently walked down selected in plant operator actions to
determine whether the actions could be completed as written, components
were accessible, the necessary equipment was pre-staged and controlled,
and that environmental conditions such as post-accident radiation
levels, temperatures, and lighting would not hamper accomplishment of
the tasks. These direct observations also provided another method to
determine whether the V&V instruction and its implementation was
adequate. During the October onsite inspection, the team used the draft
E0Ps scheduled for PRC approval in Novem3er. During the December onsite
l inspection, the team used the PRC conditionally approved E0Ps. During
, - the January onsite inspection, the team continued to use select PRC
l conditionally approved E0Ps and, due to previous NRC team findings,
l revisions to the E0Ps,
-b. Observations and findinos
1. In October the team recognized that the licensee was in the
arocess of performing the V&V on the draft E0P in plant actions.
10 wever based upon the licensee's response as to how certain
P
aw a ++ + %----,w-#%e- -e--,.-=---r---=r,r --ww ----.r~-,r-= * r- ee rr-e v--e -- w w w e ee w ww =,
._
10
areas of the V&V had been dealt with and direct observations from
in plant walkdowns, the team expressed a concern to the licensee
that the in plant portion of the V&V process was insufficient.
Specific findings and observations supporting this perspective
were:
- E0P 14. Enclosure 13. Ste)s 13.3 and 13.5. directed the PPO
to align four valves in t1e 119 feet AB penetration area.
These valves were required to be operated to initiate and
secure high pressure auxiliary spray. One of the valves was
approximately 10 feet above the floor and may be accessible
with a tall stepladder. However, only an extension ladder
was staged for the job and it could not be positioned to
3rovide access to the valve due to piaing configurations.
Jpon identification to the licensee. 3C3 C97 7324 was
initiated.
- E0P 14. Enclosure 20. Steps 20.12 detail item 6 and 20.27.
incorrectly identified "MVP 1A. A Makeup Pump." 4160 V
breaker being in cubicle 3A 3. The correct location was 3A-
10.
. E0P 14. Enclosure 21. Step 21.1. directed I&C to install
flow instrumentation. Numerous problems were identified
with this step such as: incorrect part numbers; the
equipment was available for general use; 1&C technicians
were not trained on the step; the equipment did not have a
current calibration; the transmitters were not wired up
requiring the technicians to obtain the tech manual and
wiring diagrams from document control (not always manned);
the parts were in the warehouse (not always manned) outside
the protected area and required operating a forklift to get
them off the shelves; and the required gaskets were not
identified or pre staged. The licensee initiated PC3 C97-
7365 regarding Enclosure 21.
. E0P-14. Enclosure 6. step 6.3.1 required the installation of
a hose between valves CXV-358 and MSV-524 to fill the OTSG
blowdown line. At the request of the team a non-licensed
operator attempted to perform this action. The hose to
accomplish this task was comprised of numerous segments
connected by Chicago fittings and was not long enough to
join the two points. Also, the hose reel storing the iose"
and the hose were not positively secured. Upon
identification the licensee initiated PC3-C97-7125.
. Based upon verbal licensee responses the radiological
mission doses for performing in-plant actions, except
initiating RB purge for hydrogen control, had not been
appropriately considered.
.
11
- The licensee did not have time studies for accomplishing in-
plant actions. Without such information there was no way to
ascertain the integrated effect on personnel resources that
the in plant actions would have.
- Following the team's inquiry as how chemistry sampling
actions could be accomplished under postulated electrical
bus failures, the licensee initiated PC3 C97 7244 : " ting
that chemistry did not have procedures or equipment to
support the E0Ps with a loss of ES train B power or during
an SBO,
- Based on the team's walkdowns, it was not apparent that the
licensee had taken into account that an extra operate' may
be necessary to stabilize some of the ladders used to
operate equipment based on physical constraints. Typically
it would take approximately 15 minutes to operate each valve
requiring a ladder for access. Also, in some cases, the
o)erators would be hampered by a lack of emergency lighting,
W11ch could not be compensated for by using a conventional
flashlight, e.g., the job took two hands and was 15 feet
above the floor.
2. In response to the team's perspectives, the licensee provided
additional guidance to the personnel performing the V&V to ensure
lighting, labeling, proper equipment staging and spatial
restrictions were appropriately addressed. Pictures were taken of
the equipment to be operated in detail enough to see the equipment
labeling, A time study was performed to help recognize any
conflict in resource allocation for in-plant actions. including
maps depicting the most probable routes non licensed operators
would use. Saecific equipment staging deficiencies such as the
hose for OlSG ] lowdown and the ladder for the pressurizer
auxiliary spray were quickly rectified. The team's observations
regarding mission dose were considered for action.
Extensive short term and long corrective actions for chemistry
sampling were established which would be implemented over a number
of months. However, the licensee's V&V process would not have
identified these problems since the V&V efforts as implemented
were exclusive to operator actions and did not extend to support
personnel. This limitation in the way the V&V process was
implemented also explained why the licensee had not identified the
need for TSC procedures as discussed in section 03.1.b.3. Failure
to ensure chemistry actions could be performed when directed by
the E0Ps was another example of violation. VIO 50/302-97-12 01.
" Inadequate Implementation of Teil Action Item E0P Order,' 'n that
instructions were not complete and compatible with condit Lns
(differing electr_ical bus availabilities).
3. In December 97 and January 98. following completion of the
_
.
( !
12
-
licensee's V8V of the E0Ps. the team noted improvements with .
respect to delineating the preferred ingress egress pathways,
support tools and equipment, and determining expected duration '
times necessary to complete activities., These additional actions
were the result of management providing a list of expectations for
performing in plant validations which will be incorporated
directly into Al 402C.
However, some of the team's October 97 concerns were not
odequately addressed. These included the lack of radiological
mission dose assessments for numerous in plant E0P actions and the
questionable ability to perform post accident RB hydrogen control
actions.
(a) On 3/3/97 the licensee initiated PC3 C97-1533 identifying
concerns with operators accessing a MCC in the intermediate
building following a SBLOCA due to the environment. This
concern expanded into restart issue D65. " Post Small Break
LOCA access to Intermediate Building and Auxiliary Building
for required operator actions." As part of the resolution
to the extent of condition for the PC and D65 the licensee
determined that there were " required" and "not required"
actions primarily based on a vendor analysis of E0P in plant
operator actions completed in July of 1997. This analysis
was based upon whether alternate actions were available to
perform the same function. The analysis did not evaluate
whether the actions could be accomplished based upon
radiological conditions. Also, the E0Ps or the V&V of the
E0Ps did not take into consideration whether an action was
" required" or "not required." Therefore, all E0P actions
would be attempted, whether accessible or not.
On 10/18/97 the licensee initiated PC3-C97 7125 on the lack
of a radiological dose assessment for initiating OTSG
blowdown following a SGTR. The PC was dispositioned to
perform the dose calculation by 3/30/98, after the scheduled ,
restart of the reactor. The PC further stated that this was
not a required action. following the )hilosophy used to
disposition PC3 C97-1533. This was tie rationale as to why
a large number of in plant E0P actions such as initiating
OTSG blowdown, aligning high pressure auxiliary spray and
equalizing pressure across the MSIVs did not have dose
assessments.
As previously mentioned. NUREG 0737, l.C.1. required in
part, via the Confirmatory Order issued February 21. 1984,
that licensee validation programs ensure that instructions
to operators in emergency procedures be compatible with the
conditions. Also. NUREG 0737, ll.B.2. " Design Review of
Plant Shielding and Environmental Qualification of Equipment
for Spaces / Systems Which May be Used in Postaccident
_ _ . . . . _._.._._____ _ _ _ _ _ _ ._ _ _ . _ . _ . _
__. ___ __ . _ _ . _ _ _ . _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ ._ _
(
l
13 - 1
Operations.' stated that licensees were to provide adequate
'
access to vital areas to increase the capability of ;
operators to control and mitigate the consequences of an
accident. Per 11 B.2, a vital area was defined as, "Any
'
area which will or may require occupancy to permit an
operator to aid in the mitigation of or recovery from an
i accident is designated as a vital area." The licensee was i
required to comply with NUREG 0737. Criterion II.B.2 in a
-
Confirmatory Order issued March 14, 1983.
'
'
Due to the incdequate disposition of PC3 C97-1533, an
untimely corrective action was specified in PC3 C97 7125.
Also, due to an inadequate extent of condition disposition
of PC3 97 1533 the licensee did not comply with the 2/21/84
Confirmatory Order associated with NUREG 1.C.l. the 3/14/83
Confirmatory Order associated with NUREG 11.B.2 or
Administrative procedure Al 402C AP and E0P Verification
and Validation plan. Enclosure 5. Evaluation Criteria for
Procedure Validation, which required an assessment to ensure
in plant actions are not hampered by inaccessibility or
environmental conditions. 10 CFR 50. Appendix B, Criterion
XVI. Corrective Action, requires conditions adverse to
quality be promptly identified and corrected. Failure to
adequately and promptly correct the conditions adverse to
quality identified in PC3 C97 1533 and PC3-C97 7125 is an
exemple of violation. VIO 50/302 97-12-02. ~1nadequate
Corrective Actions." of 10 CFR 50. Appendix B. Criterion
XVI. ,
(b) The licensee wrote a new E0P 14. Enclosure 21. RB Hydrogen
Management, to bring the actions for post accident
containment hydrogen management into the E0P network.
During the inspection the licensee decided to leave these
actions in OP 417. Containment Operating Procedure. Rev. 73,
due to questions concerning equipment and personnel
availability to install flow elements and the actions would
not be required until at least ten days after the accident.
However, neither the E0Ps nor the TSC 3rocedures directed
the operators to implement OP 417 if R3 hydrogen levels
increased. This is another example of the 1984 Confirmatory
Order violation. VIO (50/302-97-12 01) ~1nadequate
'
Implementation of TMl Action item E0P Order." in that
instructions were not complete. Also. OP 417. step 4.8.2.
directed I&C to install flow instrumentation but, no 6se
calculations were performed for this job. This is another
example of inadequate corrective action violation. V10
50/302 97 12 02 ' Inadequate Corrective Actions."
--
-. - - - .
14
4. In December 98 and January 98, the team identified other s
and general deficiencies reflecting inadequacios in theV V&pecific
process for in plant actions. These included: ,
the correct fitting in the E0P box for venting the OTSG
blowdown line prior to placing the line in service per E0P.
14. Enclosure 6. step 6.3. There were cver ten fittings in
the box but only one of the fittings would have fit. This
box contained equipment associated with numerous E0P
enclosures, not just Enclosure 6. and the licensee did not
dedicate this unique fitting for Enclosure 6 within the box.
The licensee initiated PC3-C97-8459.
- Adequate support staff was not designated to perform the E0P
actions. Two chemistry personnel were necessary to
reasonably accomplish E0P actions. Although two were
normally on shift, only one was required by the licensee's
administrative procedures. E0P 06. SGTR. step 3.15 required
maintenance personnel to repair a MSSV that would not
reseat. The licensee did not maintain qualified maintenance
personnel on back shifts to perform this E0P action and no
administrative procedure required their presence.
- In January 97, during an SB0 simulator scenario, the team
observed operators attempt to implement Enclosure 1 of AP-
770, Failed EDG Recovery, when directed to by E0P 12. 5B0.
At step 3.1 the crew could not perform a reset of relay EDG
86, stopping the recovery. The location and the alpha-
numeric designator of the lockout relay was mis stated in
the procedure. The licensee initiated PC3-C98 0103.
These inadequacies were indicative of not always dedicating E0P
equipment to a s
expanding the V&pecific
V process task or enclosure,
to include notperformed
E0P actions adequately
by
personnel other than operators and, less rigorous V&V efforts for
E0P actions not specifically delineated in an E0P. Also, these
were additional examples of violation. V10 50/302-97-12 01.
" Inadequate implementation of TMI Action item EDP Order " in that
the E0P instructions were not complete or usable.
5. Other less significant weakness observed by the team in Occember
97 and January 98 were:
. During the performance of a simulator scenario on 12/9/97,
the team observed the PPO performing the actions specified
in E0P-14. Enclosure 18. Control Complex Chiller Startup, as
directed by the control room operators. The PPO completed
the enclosure and verified proper operation of the cailler.
Subsequently the PPO was requested by the control room
operators to perform step 17.8 of Enclosure 17. Control
_ _ _ _ _ _ _ __ -_
15
Complex Emergency Ventilation, which required actions to
align the chilled water source to the running fan. The PPO
opened the CHV-2 valve and closed the CHV 4 valve to
complete the alignment. During the scenario activities, it
was determined that if the alignment actions required in
step 17.8 of Enclosure 17 (i.e , flow balancing) were not
performed properly, the running chiller unit could trip.
Additionally if the chiller unit was tripped in this manner,
re establishing chiller operation could require an
additional 30 minutes. T11s possible negative interaction
between the actions specified in the enclosures was not
recognized as part of the licensee's verification and
validation efforts. This is an open item pending further
analysis and review. IFI 50/302 97-12 03. " Enclosure 17/18
Interaction."
. While performing an 580 simulator scencrio the PPO was
directed to open the EFIC cabinet doors to enhance cooling.
He accomplished the task within the time critical criteria
but was slowed down by the lack of specific labeling as to
which key went to which EFIC cabinet door.
. Some of the signs. indicating which EFIC doors were to
opened in an SBO were not placed in the optimum human
factored location. Subsequently, the licensee placed the
signs in the optimum location.
'
. The ladder for operating valve SWV 60 in E0P-14. Enclosure
18. Control Complex Chiller Startup, was not optimal.
6. Throughout the inspection (including October), the team observed
that the operator actions within the control room could always be
performed with the labeling in the procedure consistent with the
simulator.
7. Throughout the inspection period the tearn found the V&V records to
be a comprehensive accounting of the issues raised during the E0P
development process, including operator comments, training
personnel observations. in plant walk down evaluations, and the
resolutions im)lemented for each issue. Additionally, the
validation boot contained a list of all procedural steps evaluated
during similar exercises with the operating crews to ensure all
potential mitigation paths through the E0Ps were formally
evaluated during the V&V process. Overall, the team considered
the detail captured in the V&V evaluation records to well be
detailed and thorough. However. the V&V efforts as captured in
these records concentrated upon control room operator actions and
discrete in plant operator actions. There had been limited V&V
efforts integrating control room and the in plant operator actions
and no efforts involving non-operators.
_ .
- - - -
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! i
!
1
l
,
16 !
6
c. Conclusions
At the beginning of the inspection, the licensee's in plant portion of
i the V&V process, which was being performed on the draft E0Ps while the
i
team was onsite. was insufiicient. There were no specific concerns !
l regarding the control room portion, based upon documentation. In
! response to the team's perspectives, the licensee provided additional
l guidance to the personnel performing the V&V. and the team noted
i im>rovements. However, even with the improvements, the team identified
'
otler specific and general deficiencies reflecting inadequacies in the
i V&V process for in plant actions due to not always dedicating E0P l
l equipment to a specific task or enclosure, not adequately ex)anding the
i V&V process to include E0P actions performed by personnel otler than
operators and, using less rigorous V&V efforts for E0P actions not
specifically delineated in an E0P. There were examples of a violation.
Also, some of the team's original concerns were not adequately
addressed, partially due to inadequate correction actions to a problem
previously identifed by the licensee associated with operator in plant
,
accessibility.
This disparity between licensed operators being able to perform control
room E0P actions and non licensed and support personnel not always being
j able to perform in plant E0P actions was consistent with the way in
which the V&V process was established and implemented. Consecuently.
l the actions directed by the E0Ps within the control room coulc always be
performed, but numerous in plant actions either could not be performed ;
i due to the lack of support perr.onnel. lack of properly stagged
equipment, technically incorrect procedure steps, not incorporating the
i
'
actions into procedures or the radiolog1 cal consequences of performing
the actions had not been assessed,
,
03.3 Writer's Guide for E0Ps
a. Insnection Stone (42001)
i
The team reviewed the liansee's E0P Writer's Guide for Abnormal and
. Emergency Opnating Trc edures (Al 402A. Rev. 8) to ensure that it
. adequately addressed e n eloping procedures consistent with NUREG 1358.
Supplement 1. " Lessons Learned from the Special Inspection Program for
'
Emergency Operating Procedures," The team reviewed the E0Ps to
,
determine if the guidance in procedure Al-402A, Rev. 8 was adhered to
,
during the development of the E0Ps and referenced procedures. The team
observed operators during simulator scenarios to determine whether the
steps were readable and the actions clear.
>
b. Observations and Findinos
The team determined that the writer's guide described the aspects of
procedure step development, including format and layout considerations.
4 procedure developer responsibilities, and step construction requirements
in a comprehensive manner The E0Ps adequately conformed to procedure
i
-._,-.--,..._.-__-m-.. ,,..w., ,,-,-,m_rm-,n_._-.,-,_,r. ..,_ .,-., v_ ,,,,,.,% r,v-_-___.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _
17
'
Al 402A, Rev. 8. The definition section did reveal ambiguity in the
definitions of the terms " verify" and " ensure." Because of the
significance of these terms as implemented in the E0Ps. a clear
differentiation between the definitions was imperative. The licensee
stated the definitions would be reviewed and rewording considered to
better reflect the expectations for the terminology. However, rarely,
during simulator scenarios, did the team observe operators having
trouble reading or understanding the direction provided in any E0P step.
c. Conclusions
The E0P Writer's Guide was comprehensive and adequately implemented in
the construction of the E0Ps. This contributed to operators rarely
having trouble reading or understanding the E0P steps during the
simulator scenarios.
03.4 [0P User's Guide
a. Insoection Stone (42001)
In October 97 the team reviewed the licensee's draft E0P 'Jser's Guide.
Conduct of Operations During Abnormal and Emergency Events (Al 505. Rev.
2). to ensure that it adequately addressed roles and responsibilities of
crew members and described the expectations for procedure usage. This
included the communications protocols required to correctly implement
the E0P mitigation strategies. In December the team reviewed the PRC
approved guide.
b. Observations and findinas
The team determined that procedure Al 505 provided sufficient guidance
regarding the roles and res)onsibilities of the operating crew members,
communication protocols to )e observed during transient response,
methods and expectations for procedure step usage including transitions
and immediate actions. The guidance also described the expectations for
procedure compliance, priority of symptoms for entry into the E0Ps. and
exceptions to the arioritization scheme. Generally, the draft guidance
was sufficient wit 1 the following weaknesses:
. Section 4.1.1.3 Performing steps out of Sequence, allowed the
crew to de) art from the pre defined sequence of mitigation steps
provided t7e step transitioned to: 1) could be carried out to
completion. 2) was within the. current procedure in use and 3)
delaying carrying out the step would negatively impact the
mitigation attempts. Additionally. the procedure recommended
prior Nuclear Shift Supervisor (NSS) concurrence with such a
departure. During an October simulator exercise. the team
observed the crew implement this rule. When questioned the crew
responded that NSS concurrence was required not merely
recommended. The team noted that the licensee did not have any
administrative controls to evaluate sequence deviations and
_ _ _ _ _ _ _ _ _ _ _ - __ _ _____ _ __ _ . _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _
18
'
operating crews could consistently use this method without
realizing that a step was mis placed. Additionally, a departure
from the pre determined mitigation strategy might negatively
impact the mitigation strategy and any such departures should have )
a sound technical basis. In the December version of Al-505 ,
sequence deviations were required to be evaluated. l
- Section 4.2.1.3, Exceptions to Symptoms, defined four situations
which were exceptions to the protocol of entering the highest
)riority E0P based on the ap)earance of the predefined symptoms.
~
- rom the initial review of t1e E0Ps it was not clear that these
exceptions were directly defined in the E0Ps which might be
affected by such conditions. Subsequently, the licensee
highlighted the four situations in the applicable E0P sections.
c. Conclusions
following revision, the licensee's E0P User's Guide was acceptable.
03.5 E0P Maintenance J Revision Guide
a. Insnection Scone (42001)
The team reviewed the licensee's E0P Maintenance & Revision Guide, New
Procedures and ProcedJre Change Processes for E0Ps, APs, and Supporting
Documents (Al 400F, Rev. 4), except for sections 4.11 and 4.12. to
ensure that it adequately addressed aspects of procedure maintenance and
revision necessary to ensure the retention of quality procedures during
the facility operating life.
b. Observations and F1ndinos
, The team verified that the guidance adequately described the
responsibilities of individuals sked with E0P revisions,
differentiated between minor and gnificant changes. and described the
processes to be implemented for revision and modification of the
procedures and supporting bases documentation.
c. Conclusions
The maintenance and revision procedure was adequate. The scope of the
NRC review did not include set point control.
04 Operator Knowledge and Performance
a, insocction Scope (4200D
During the three onsite weeks, the team observed licensed and non-
licensed ope:itors respond to simulated emergency conditions developed
by the team to test specific sections of the E0Ps. The licensed
operators were in the simulator and the non licensed operators were in
-. . -. _.
_ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ ___ - _ _- _ ___ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _
10
the actual facility.
'
'
The non licensed and licensed operators
communicated to each other via portable radios. The team evaluated )
operator performance with respect to whether the procedures were l
foll0wed, the administrative controls of procedure Al 505 were followed I
and whether management expectations were met,
b. DMervations and Findinos
The team determined that the operating crews were capable of mitigating
the transients presented. Three party communications were routinely
used by all operating crews and place keeping was adecuate to maintain
control of the mitigation actions. Also, the crews acequately
implemented the required carry over actions when the conditions were
satisfied for entry into specific carry over ste)s. Indicative of this
performance was the successful execution of the E0Ps in response to a
simulated SBLOCA with a failure of the B battery. All operators
accomplished their tasks and all time critical tasks, such as starting
the control rooms fans and chillers, were accomplished within their
required time frames.
However, there were some examples of performance inconsistent with an
E0P step. licensee management expectations as emphasized in operator
training or the licensee's administrative guidance. These examples were
partially due to individual performance errors and partially due to
training deficiencies. Specifically:
. In October 97. during a SGTR scenario with a stuck open MSSV the
crew elected not to transition from E0P 06. SGTR. to the higher
priority E0P 05. Excessive Heat Transfer, even though they met the
entry conditions. Follow up questioning revealed that the SR0s
could not state that E0P 06 contained all the required steps the
crew missed by not transitioning to the excessive heat transfer
E0P.
. In December 97, during a LOCA, the procedure reader had to be
reminded to review the symptoms after completing the immediate
actions of E0P 02. Also, in January during a S80, the team
continued to observe a weakness in scanning for symptoms after
performing immediate o)erator actions. The operating crew did not
enter E0P 12. Station 31ackout. until prom)ted twice during the
5B0. Six minutes elapsed from the time EO) 04. Inadequate Heat
Transfer (a lower priority symptom) was entered until the crew
transitioned to E0P 12. The licensee initiated PC3 C98 0104 on
this situation.
. In December 97 and January 98. when given an additional task while
performing another task. SP0s occasionally continued with the
first task before performing the second task. The SPGs did not
inform the control room licensed operators of the conflict and
request direction as to which task to perform first, which aer the
licensee was the appropriate response. As an example, an S'O
__
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I
20
-
continued closing MSV 301 & 303 once directed to shut a failed I
open ADV during a SGTR scenario in January.
. In December, during tube ruptures in both OTSGs the crew was
confused at E0P 03, Step 3.15 for securing feed to the affected
OTSG since both OTSGs had tube ruptures.
Depending upon the significance of the problem: the licensee initiated a
precursor card, was evaluating the observation for feedback into the
training program, or was providing feedback to the individual involved
as part of the continuing training process,
c. Conclusions
The operating crews were capable of mitigating the transients presented
by the team. However, there were some examples of performance being
inconsistent with an E0P step, licensee management expectations or the
licensee's administrative guidance. These performance problems were
being dispositior.ed consistent with their significance.
05 Opitator Trainina and Qualification
a. Inspection Stone (42001)
The team reviewed selected training records to determine whether
licensed personnel had been trained on the recently revisad E0Ps. The
trainirg records reviewed included lesson plans, simulator exercise
descriptions. E0P simulator evaluations, and E0P/AP revision
documentation. The team reviewed one aspect of non licensed operator
training associated with the turbine driven emergency feedwater pump.
b. Qugervations and findinas
The team determined that the lesson plan information was detailed. The
simulator exercise evaluation forms were self critical and ex) licit
regarding performance weaknesses and the reasons for such weacnesses.
The E0P training update packages. information considered different from
the initial training due to E0P/AP changes, were dctailed.
During one of the December scenarios. consistent with the E0Ps. a
licensed operator directed an SP0 to monitor the performance of the
turbine driven emergency feedwater pump for proper performance. The
team ascertained that the SP0s did not receive formal training on
resetting the over speed trip on this equipment. This was considered a
weakness of the SP0 training program. Prior to the end of the
inspection period, SP0s were trained on resetting the over speed trip.
The team satisfactorily reviewed the training material along with the
list of SPO attendees.
. - _ - _ - - , . - - - . _ _
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21
c.
'
Con _tlusions
,
The E0P/AP training program for licensed operators was adequate to
familiarize operators with the E0Ps/APs, including procecure changes,
end to assess operator performance while using E0Ps/APs while in
training. There was e program weakness of not training non licensed
secondary plant operators on resetting the emergency feedwater turbine's
over s)eed trip. The licensee provided corrective actions consistent
with t1e significance of the weakness.
08 Misse.llangppsOperationsissurs
08.1 [0PContentWeaknesse51 While observing the simulator scenarios, the
team noted select areas where the licensee's E0Ps did not optimize the
equipment available to mitigate the situation. These were:
. Not optimizing existing plant systems to provide makeup water to
the secondary or primary sides of the plant, if necessary, in E0P-
02, VSSV, in response to an ATWS.
. Not including procedural direction in E0P 07, Inadequate Core
Cooling, to consider using the condensate booster pumas if all the
other supply source (EFW, AFW, MFW) prime movers to tle OTSGs were
not available.
. Not providing a local procedure to start the AFW diesel if it
should not start from the control room.
The licensee acknowledged these observations and indicated that they
would be reviewed for possible action.
08.2 ICloseO URI 51 v ?/96 06 10: Justification for Removal of Thermo Lag
Protection from aurce Range Instrumentation
lhe immediate actions of E0P 02. Vital System Status Verification. Rev.
4. step 3.3, required immediate emergency boration of the RCS until the
reactor was shutdown if nuclear instrumentation did not indicate the
reactor was shutdown following depression of the reactor trip push-
button. These actions were consistent with the TBD. E0P-10. Post-Trip
Stabilization. Rev. 3. step 3.4 recuired RCS boron sampling if the
source range instrumentation failec. These actions addressed the loss
of source range instrumentation via fire which would not involve
evacuation of the control room. Therefore, this matter is considered
resolved.
II. Main _tenance
M3 Maintenance Procedures and Documentation
M3.1 [ontrols for Maintrnance in PrpximitY to In-Plant E0P Actions
. . _ _ _ _ _ _ _ _ _ _ _ _ .. _ _. _ _ _ __ _ _ _ . _ _ _
l
22 ;
3
r
4 :
a. Insoection Scone (42001) i
As a result of the extensive scaffolding erected within the facility !
! while the plant was in cold shutdown, the teem evaluated whether the
- work control process included consideration that the work could impact
- in plant E0P actions by inhibiting access to those locations. ,
1
- b. Observations and Findinas , t
i
- As a-result of the team's questions in this area, the licensee
determined that no procedural controls existed to evaluate whether
'
maintenance activities could affect E0P in plant actions. The licensee
'
initiated PC 3 C97 7923 on this matter. At the end of the inspection
the licensee was formulating the corrective actions which the licensee
verbally indicated would include adding these administrative controls to
the work control process.
'
c. Conclusions
The work control process did not consider that the work could inhibit :
access to in plant E0P action locations. The licensee was formulating
- corrective actions to this weakness under their established corrective
> action program.
M3.2 Surveillance Proaram for ECCS Exte,nal Leakaae Associated with HPI
1
Picavback
a. Insoection Stone (42001)
- The team reviewed the licensee's program to meet TS 5.6.2.4. " Primary
Coolant Sources Outside Containment." to ascertain whether components
(piping, valves, etc.) of the HPl piggyback function had been included
l in the program. TS 5.6.2.4 required a program to provide controls to
minimize leakage from those portions of systems outside containment that
could contain radioactive fluids during a serious transient or accident
to levels as low as practicable. The systems include Low Pressure
. Injection. Reactor Building Spray, and Makeup and Purification. The
'
program included the following: a) Preventative maintenance and
periodic visual inspection requirements: and b) Integrated leak test
requirements for each system at refueling cycle intervals or less.
b. Observations and Findinos
'
The team determined that Com311ance Procedure (CP) 149. Primary Coolant
Sources Outside Containment Program. Revision 2. implemented this TS
'
required program. In response to the team's westions regarding the-
piggyback function, the licensee reviewed-the issue in detail and
identifled that portions of the HP1 system were not included in CP 149.
4 The' licensee initiated PC 3 C97-8496 on December 13, 1997, to resolve
this deficiency. -During the PC follow up, the licensee further
identified that there was not a program to meet the periodic inspection
_ _ . - _ _ . - _ _ _ _ . _ _ _ _ _ . _ . _ . _ _ _ _ ___ . _ . . __
_ _ _ _ _ _ . _ _ _ _ . _ _ _ . _ . _ _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _
-
l
,
!
$
'
23
<
- requirement. These inadequacies were a violation of TS 5.6.2.4. The :
team reviewed the licensee's planned corrective actions for the PC and
determined that the corrective actions would adequately correct the ,
deficiencies. Also, when all applicable external leakage that presently l
existed was tabulated, the post-accident dose consequences requirements -
were not exceeded. This licensee identified and corrected violation is
being treated as a Non Cited Violation. NCV 50/302 97 12 04. " Inadequate
External Leakage Surveillance Procedure." consistent with Section
,
VII.B.1 of the NRC Enforcement Policy. ;
c. Conclusions
The licensee's program for implementing TS 5.6.2.4 was not adequate, but
the actual external leakage did not exceed post-accident dose
consequences requirements. The licensee was taking appropriate
corrective actions to correct this non-cited violation.
M3.3 echnical Content of Periodic Inventory Proaram for In Plant E0P,
inment
a. Insce-tion Scoce (42001)
In January the team reviewed the E0P/AP toolbox surveillance checklist
to ensure that the necessary tools were properly staged in the
designatedlocationsconsistentwithSP-306.WeeklysurveillanceLog.
This was accomplished by selectively observing whether the contents of
E0P/AP tool buxes contained the equipment listed on the licensee's
surveillance checklist. The team also verified whether all the keys
required for E0P/AP implementation per SP-306 were in the designated key
box in the control room,
b. Observations and Findinas
The team observed one difference between the box and the checklist for
the boxes reviewed. E0B-06 contained two female fittings while the
checklist required at least three. The licensee immediately placed
another fitting into the box and initiated a precursor card. After
preliminary evaluation the licensee verbally informed the team that the
checklist was in error. All keys were present in the control room key
box. The keys contained a number ossignator consistent with the E0Ps.
They did not include a label with the s)ecific pur)ose for the key which
could reduce confusion in identifying tie correct cey. Most of the tool
boxes were not physically restrained. When the team questioned the
licensee, the team was informed that~the boxes had been previously
walked down and satisfactorily evaluated by engineering personnel.
c. Conclusions
The technical content of the periodic invantory controls for in pla ;
E0P equipment was adequate.
- .. -- -. - . - . . - _ _ _ . - _ - _ - - - . _ . - - , - . -- --
_ _ _ _ _ _ _ _ _-__ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _
24
' III. Enaineerina
El Conduct of Engineering
E1.1 Csiculations Sucoortina E0P Actions
a. Insoection ScoDe (42001)
During the onsite weeks the team reviewed several engineering
<
calculations supporting E0P actions or set points. The team reviewed
these calculations for accuracy, appropriate assumptions, and compliance
with applicable standards. The applicable standards included:
Instrument Society of America (ISA) 67.04, part 11. as referenced by
instrumentation and controls Design Criteria Instrument String Error / Set
point Determination Methodology and ANSI 45.2.11. 1974. Quality
Assurance Requirements for the Design of Nuclear Power Plants,
b. Observations and Findinas
,
The team's observations and findings were:
1. During the first onsite week (October), the majority of the
calculations su) porting the E0Ps were being created or revised.
Therefore, the aulk of the calculations reviewed during the first
nnsite week were issued prior to 1995. During the second onsite
week (December) some of the calculations were still being created
-
or being revised, partially due to corrective actions from the
team's observations during the first onsite week. A substantial
portion of the calculations were completed just prior to the '
team's arrival onsite. Therefore. during the second on-site week.
only a limited number of these newer calculations were reviewed.
During the third onsite week (January), a slightly larger sample
of the newer calculations were reviewed.
2. During the first onsite week, numerous E0P instrument loop
calculations contained the same errors as discussed in NRC
Inspection report 50-302/97 01. The calibration temperatures were
not specified and the procedures for calibration of instruments
located in the AB did not assure that the AB temperatures were
maintained within the temperature ranges assumed in the instrument
loop uncertainty set point calculations. Additionally, other '
calculational assumptions were not verified. An example was
calculation 190-0022. Revision 0, associated with EFW flow which
assumed the transmitters in the AB were calibrated at 75'F.
However, the full temperature range was 55 - 95*F. Therefore, the
instrumentation could be calibrated at the low end of the
temperature band and operated in the high end. This would induce
a process bias in the instrument loop uncertainty not accounted
for in the calculation, The licensee documented the error in
calculation 190-0022 on PC 3-C97 7154. Another example was
.
- - - - . , , . - - - . , - -e . -., , , , - ,,,--y ,n , .n, . , , . . , . . . , . . - - , . -. ,sw. .,, e
- .- - --. - - - - . - . - - - . - - - - - - - - . - . . -
l
2
1
25
1
'
5
documented in PC 3 C97 8447. The PC was written to document
- Analysis / Calculation deficiencies identified when assessing the '
- loop uncertainties in 191 0028 Revision 1. FWP-7 Flow Indication,
j The calculation failed to include ambient temperature effects,
static pressure zero effect, static pressure span effect, static ,
pressure, span shift. and other process effects due to temperature
and pressure.
The extent of the licensee's corrective actions to Violation 50- I
'
302/97 01 07. Instrument Loop Uncertainty Set point Calculation
Assumptions Not Translated into Procedures, was inadequate. 10 '
l
1 CFR 50. Appendix B. Criterion XVI. Corrective Action, requires
l conditions adverse to quality be promptly identified and
3
corrected. The licensee's failure to identify and correct
- calculations supporting E0P related set points as part of the
2 corrective actions for Violation 50 302/97 01 07 is an example of
'
an inadequate corrective actions violation. V10 50 302/97-12 02. :
" Inadequate Corrective Actions."
3. During the December onsite week, one of the few existing <
'
radiological dose calculations was determined as inadecuate.
Calculation M93 0006. Rev. O. determined the post accicent mission
, doses to purge the RB for hydrogen control. The calculation
'
assumed a non conservative time frame to initiate the purge as
well as other errors. The doses were calculated starting 25 days
- after the accident. FSAR Section 148.3.3 stated that purging may
start as early as 250 hours0.00289 days <br />0.0694 hours <br />4.133598e-4 weeks <br />9.5125e-5 months <br /> after the accident. Also, the time
'
assumptions for operating valves were not validated. Step 4.9.8.2
of OP 417. Containment Operating Procedure, directed throttling
open LRV-121 or 123 and establishing a calculated flow rate, lhe
i time to accomplish this step was assumed to be 5 minutes. This.
time was not validated and may be non conservative since the valve
>
was located approximately 10 feet from the flow indicator and the
flow indicator would be facing away from the valve. The licensee
documented the problems with this calculation in PC 3 C97 8366.
The licensee's Quality Assurance Program as described in the USAR
listed ANSI 45.2.11. 1974 " Quality Assurance Requirements for the
Design of Nuclear Power Plants." under the committed standards.
ANSI 45.2.11, subsection 3.2 states in part "The design input
"
shall include but is not limited to ... Environmental conditions
anticipated during ... operation such as ... nuclear radiation."
and .. " Operational requirements under various conditions such ,
as ... plant emergency operation . " Failing to consider
radiological effects properly during the design input is an
examale of - violation. VIO 50/302 97-12 05. " Poor Calculations."
of A4SI 45.2.11.-
>
4. Numerous other calculations issued prior to 1995 were not
consistent with ANSI 45.2.11. subsection 4.2. This subsection
. states " Analysis shall be sufficiently detailed as to purpose. '
.
k
e. -4 - - - . . , - - - m m.,--,,<,....,,_r_.,-w--- ,#-.w,#.e e., ,
-
. . _ . , w. ,7___m., y v-e w,.--,,.- ,m ,,w-,.-,- %,.. ,,.m ,,-.--_.,_.,_w.myw,-wy my_ _ _
. ._ _ __ _ _ _ . _ _ _ _.__ _ _ _ ._ ._ _ _ _ _ _ _ ._ ,
1
- 1
26 )
-
method, assumptions, design input. references and units such that
a person technically qualified in the subject can review and
understand the analyses and verify the adequacy of the results
without recourse to the originator." As an example.. Calculation
"
E 90 0023. Evaluation for Containment Spray between pH 4.0 and
12.5. assumed a corrosion rate for carbon steel pi j
,
a boric acid containment spray of 50 mil per year. The ping exposed to ,
, calculation stated that the expected corrosion rate was 10 mils
but, corrosion rates could be greater than 50 mils. Nowhere in '
the calculation was the rational for the selected corrosion rate
- provided. Upon identification to the licensee, the licensee
initiated a precursor card report. This is an example of '
. violation. VIO 50/302 97 12 05. " Poor Calculations," of ANSI
. 45.2.11.
5. Although a small sample size was reviewed by the team, the
calculations issued in 1997 were far better and did not contain
any of the errors discussed above. Only one minor problem in the
"new" calculations was observed. This was the failure to
reference an affected calculation when a value in the base
calculation changed.
c. Conclusions
calculations issued prior to 1995 contained numerous errors.
q
Generally,ly,
Occasional the calculations did not contain enough information to
enable a person, who was technically qualified in the subject, to review
and understand the analyses and verify the adequacy of the results.
This was a violation. Prior to the team's arrival, the corrective
actions to known calculational inadequacies had not extended to the E0P
set point calculations which was an example of an violation. Although a
small sample size was reviewed by the team, the calculations issued in
1997 to support E0P set points were far better.
El.2 Low Pressure in.iection Crossover Mode of Operation
'
a. Insoection Scone (42001)
Due to the licensee not directing the crossover mode of LPI operation be
used in the E0Ps, the team reviewed the licensing basis documents for
long term core cooling following a LOCA as discussed in 10 CFR 50.46 and
10 CFR 50. Appendix K, These documents included B&W topical re) orts,
the licensee's FSAR, a safety evaluation to change the current SAR and
applicable correspondence. Also, the team reviewed the NRC's SERs
associated with ECCS with respect to long term core cooling.-
b. Observa.1fons and Findinas
1. The team determined that during at least two time periods after
the operating license was vranted. there was no procedural
guidance to use the LPI crossover line with flow split between the
.- .- -. _ - - .- .- -.--.- -
-- - .- . . -- - ----.- _.
I
27
two LPI lines (the crossover line method of long term core ,
cooling, option #1 in BAW 10103A and BAW 10104) to mitigate the !
'
consequaices of a LOCA. The first time period was from 7/79 until !
6/89. The second time period was 5/2/96 until the issuance of
, Procedure EH 225E. Guidelines for Long Term Cooling, on 1/27/98.
EM 225E was issued, due to the NRC E0P inspection team identifying
the lack of such a procedure to the licensee in December, 1997.
Originally, depending upon plant conditions, the licensee used the !'
. crossover line method of long term core cooling in two procedures.
l The procedures were EP 106. Loss of RC/RC Pressure, and OP 404.
Decay Heat Removal. In 1979 both 4
that EP 106 referenced OP 404 and, procedures
in Revision 24 dated were7/3/79
revised of such i
OP 404, the use of the crossover line method was deleted.
.
in June 1983 the licensee instituted the first set of symptom
based procedures for dealing with transients and accidents with
AP 380. Engineered Safeguards Actuation, superseding EP 106. In
Revision 20. dated 6/29/92 of AP-380. a new step 3.8 was added
directing use of the crossover method if an LPI pum) was
unavailable. Also. Revision 73, dated 6/12/89 of 0) 404, re.
'
instituted the use of the crossover lines with flow in both
injection lines provided there was adequate subcooled margin in
section 4.13. In Revision 83, dated 3/4/92 to OP 404, the use of
the crossover line method of core cooling was transferred to
section 4.12. However, step 3.8 to AP-380 was deleted in Revision
22 on 4/8/93 and, section 4.12 to OP 404 was revised on 5/2/96 in
revision 101. Revision 101 removed the crossover method along
with the deleting the pressurizer auxiliary spray as a boron
precipitation control method. Therefore, for a second time
period. 5/2/96 until the NRC E0P inspection identified to the
licensee in 1997, there was no procedural guidance on using the
crossover line method of long term core cooling. Section
- 6.1.2.1.2. Low Pressure injection, in the licensee's USAR stated
"The LPI System is provided with a crossover line to permit one
LPI string flow of 3.000 gpm to be split equally, thus providing a
minimum of 1.500 gpm flow to both core flooding injection nozzles
simultaneously should a core flooding line or one LPI pump fail.
Redundant transmitters and indicators are provided for LPI flow
me:surement and indication. The LPI crossover injection mode of
operation is accomplished by opening the crossover line, provided
with a two way flow element between the separate and independent
LPI strings, and remotely adjusting the flow through the crossover
line to 1.500 gpm via two (one in each LPI string) electric motor
operated valves (see Figure 9 6).'
Section 14.2.2.5.4 ECCS Qualification, stated that "In order to
qualify the ECCS. the NRC placed requirements on the ECCS to
ensure that the health and well being of the puolic is not
impacted. These requirements are specified in 10 CFR 50.46 and 10
CFR 50. Appendix K. The criteria contained in Part 50.46 are
.
F
'
e v e-- - - + - - v- . w- w e- w. Piu P e- y+g- g.9y-r---y.e -y9r- u *- em'te-e ey 5-11 T-- 'F----N
__ . . __ _ . _ _ _ _ ____ _ _ _ .__. _ . _ _ _ ._ _ __._-
t
i
'
28
applicable to all sizes of LOCAs and are necessary in order to
verify adherence These criteria are as follows ... A path to i
long term cooling must be established." This section further
stated that BAW 10104. Rev. 3, was the methods report on how the
computer model used to ensure compliance with 10 CFR 50.46 will be
- assembled and run. Also, the "The LBLOCA application report for
'
the 177 FA lowered loop plants is BAW 10103A
Topical Report BAW 10103A. Rev. 3. "ECCS Analysis of B&W 177 Fuel
Assembly Lowered loo) NSSS." and Topical Report BAW 10104. Rev. 3.
"ECCS Analysis Of B&W's 177-FA Lowered loop NSS ~ discussed use of
the LPI crossover in Chapter 10. Long Term Cooling. Section 10.2
stated in part that "Several alternate modes of operation of the
ECC systems can be used during long term cooling, if necessary,
while maintenance is being performed on normal equipment:
1. One LPI pump operating with crossover line valves open: flow
split between the two LPI lines by the control valves.
2. Each LPI string operating and the LPI pump in each LPI
string operating and pumping through its own injectio,' line.
3. One LPI pump operating with injection through its associated
injection line and with the crossover to the associated HPI
string open: the associated HPl pump would be pumping
through its HPI lines."
'
Section 10.2 further stated in part that "With either of the two
LPI pumps operable. ECCS injection flow can be maintained through
two flow paths."
Pending further NRC review of the safety evaluations associated
with these procedural changes (revision 101 to OP-404 on 5/2/96
and revision 24 to OP 404 on 7/3/79), this matter is considered
unresolved. URI 50 3t?/97-12 06. " Previous LPl Crosstie Safety
Evaluations."
'
2, The team determined that the a recent change to the FSAR
describing the LPI crossover method of long term core cooling
following a LOCA was not consistent with the topical reports
mentioned above.
Prior the initial licensing of Crystal River, a number of issues
arose regarding the ECCS performance evaluation. Earlier versions
- of Topical Report BAW 10103A. BAW 10104 and BAW-10064 "Multinode
Analysis of Core flood Line Break for B&W 2568 MWL Internal Vent
Valve Plants." made u) a part of the a)plicant's method of showing
compliance with 10 CF1 50.46 and 10 CFR 50.- Appendix K. In NRC
i
l
-
, _ _ ,, _ _ _ . - - _ , --
. -. -,_.,..-,...._,_..-..,- _ .- - _ . , . . _ _ _ -
,
-
i .
.
'
29
- SER supplement 3, 12/30/76. the NRC concluded that the method used
by B&W in calculating the fuel cladding temperature during the
blowdown Dhase did not conform to the requirements of 10 CFR 50,
i' Appendix K. This directly impacted BAW 10064. which was a <
com) uter analysis that essentially terminated once ECCS flow (via 7
an eiP! pump and the intact core flood tank) exceeded the boil off :
rate. Therefore, the analysis terminated within a half hour of !
accident initiation. Subsequently. B&W properly performed the
analysis and submitted it as A
- which was accepted by the NRC.ppendix 3AW 10103. C Rev. to 3.The nev' analysis als
'
once the ECCS exceeds the boil off rate within 20 minutes of
, accident initiation. Therefore, the NRC accepted Topical Report '
- BAW 10103A. Rev. 3. *ECCS Analysis of B&W 177 Fuel A:;sembly
! Lowered loop NSSS." and Topical Report BAW 10104. Rev. 3. *ECCS
Analysis Of B&W's 177 FA Lowered loo) NSS." as the method and
<
applications for complying with 10 C:R 50.46.
Never was the applicability of the long term core cooling methods
described in the original versions of BAW-10103 and 10104 an
issue. The original SER of 7/5/74, stated in part "The low
pressure injection system lines are equip)ed with a crossover line
inside the auxiliary building so that eac1 LPIS pump is connected
to both core flooding tank (CFT) nozzles on the reactor vessel.
Manually operated valves in the crossover line will be arranged so
in the unlikely event of the simultaneous occurrence of a break at
,
the worst location in a CFT line and the loss of one LPIS. half of
! the flow of the other LPIS pump will reach the reactor pressure
'
vessel to insure adequate long term t. ore cooling."
On 1/2/98 the licensee's onsite review committee, the Plant Review
Committee, approved a safety evaluation completed the day before '
authorizing a change to the Updated Safety Analysis Report (USAR).
The USAR charge was FSAR6 R24-33 and concluded that no unreviewed
safety question existed. The USAR change revised a portion of
section 6.1.2.1.2. Low Pressure injection, and inserted a new
,
section. 6.1.3.1.3. Core Flood Tank (CFT) Line Break SBLOCA. The
'
section 6.1.2.1.2 revision did not address the use of the LPI
crossover if a core flood tank line failed and/or one LPI pump
failed due to plant s)ecific design limitations. The new section ,
'
6.1.3.1.3 discussed t1e CFf line break consistent with BAW 10103.
Rev. 3. Appendix C. This USAR change appeared 'o be in response 1
to the NRC's E0P inspection team identifying ti . previous
.
procedure changes el minated using the crossover line for long
term core cooling. !
Pending further NRC review of the safety evaluation surrounding
this change, this matter is unresolved. URI 50 302/97 12-07.
" Current LPI Crosstic Safety Evaluation."
'
,
J
f
s--_..,,,.3.,..-~+-~,-m ,..--y,,, .c,,-. , . , - . , , _ , , . , .+.,.s.~... , , . - --,m,~, , , . g,m mm 9 y , .
l
l
l
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i
! 30
)'
,
>
c. fanclusions
During at least two time periods after the operating license was >
granted there was no procedural gu: ' ..;e to use the LPI crossover line <
- with flow split between the two LPI sines (the crossover line method of
,
long term core cooling, chapter 10 option #1 in BAW 10103A and BAW
I 10104) to mitigate the consequences of a LOCA. The first time period
was from 7/79 until 6/89. The second tima period was 5/2/96 until the
"
i present. A recent change to t'1e USAR regbrding the LPI crossover line
! method of long term core cooling was inconsistent with applicable i
! topical rC ,ts. The NRC will further review these unresolved matters,
i El.3 ECCS Piaavbeck Mode of 00eration
'
a. Insoection Stone (42001)
Due to the licensee directing unrestricted HPI operation in piggyback,
in December and January the team reviewed the technical requirements
'
contained in the original purchase order for the HUPs (HPI) and compared
these requirements to how the E0Ps directed use of the pumps.
-
b. Observations and Findinas
The team determined that the original purchase order only specified one
! day of post accident operation. Whereas, post accident LOCA operation
of the MUPs while taking suction from the discharge of the LPI pumps
which in turn take suction from the reactor building sump, known as the
- piggyback mode, could be necessary for 30 days. E0P 08 directe
- 1 use of
1 the piogyback mode for an unspecified period of time. Operatim in this
4 piggyback mode was option #3 of the long term core coolina options
stated in BAW 10103A and 10104 (see El.2 above). Chapter 10 of BAW
4
10103A and BAW 10104 stated in part. "The durat!cn of long-term cooling
is the per.iod between the onset of long term cooling and the end of core
- cooling requirements, . . , The exact duration of long-term cooling will
'
vary. . .. A realistic assessment of the duration for the worst case is
approximately one month,"
Not purchasing the pumps for the appr,,'opriate post-accident time duration
"
is violation. VIO 50/302 97 12 08. Incorrect HPl Pump Purchase Order,"
, of 10 CFR 50, Appendix B. Criterion IV, Procurement Document Control.
- This criterion requires that measures be established to assure
- applicable regulatory requirement and design bases are suitably included
in the documents for procurement of. equipment.
,
C, ConcluligD}
The MUPs used for ECCS high pressure injection were not purchased to
specifications commensurate to the duty to De incurred during a
y postulated post accident-LOCA_, This was a violation.
,
W
.
d
.-w - r.+-w.,-w-rw-- -w.ww. wr y > < rev - w g ur,*-- or,-,-w.gpw-%-,,r e,- o y - ev- -w t --e v - -se e ,n -w o .. m-a ,-4.g-m9 r v--re<=-*-ew -ry----
_
31
El.4 (EDG) Start Loaic
a. Insoection Scoce (42001)
The team reviewed the EDG logic and control arrangement interface with
the air start motor controls to ensure that the design was consistent
with regulatory requirer.ats. The review was prompted by a discussion
with a licensed operatoi shen it was inferred that the EDG start
circuitry could allow the continued application of starting air to an
EDG until depletion of the staring air.
b. Observations and Findinas
The team determined that the air start circuitry did not allow such a
set of conditions. and was designed to 3revent such an occurrence
automatically. Operator training was peing provided to prevent
restarting a tripped EDG until after an emerger y shutdown relay was
allowed to " time out" for at least 60 seconds r.ior to attempting a
restart. The team reviewed training records and intervicwed operators
to assure operators were aware of this requirement.
3
c. Conclusions
) The EDG air ctart circuitry was properly designed to prevent continued
application of starting air to an EDG until depletion of the staring
air, and appropriate operator training had been provided on how to
respond to a tripped EDG.
E1.5 Position of LPI iniection Valves. DHV-5 and DHV 6
a. Insoection Scooe (42001)
Due to discussions with the licensee as to why the LPI crossover lines
were not being used in the E0Ps. the team reviewed the circumstances
surrounding why the LPI injection valves. DHV-5 and 6 (originally
- . designated DH-V4A and DH-V4B). were normally closed.
I
I b. Observations and Findinas
The team determined that as part of the licensing review for Crystal
River, the NRC issued a 12/8/75 request for information regarding the
ECCS analysis. One question s3ecifically addressed the normal position
of valves DH-V4A and DH-V4B. t7e LPI injection valves. Question 2c
stated "FSAR Figure 9-6 shows LPI valves DH-V4A and DH-V4B to be
normally closed. To allow low pressure injection subsequent to a CFT
line break and a single active component failure. '.hese valves must be
E
recuired by Station Technical S]ecifications to be. open, power removed,
anc breakers locked open. . T1ese changes provide assurence that
abundant core cooling is available for a CFT line break and further
minimize the potential for a LOCA outside containment."
E
_ _ _ _ _ - _ _ _ _ _ . _ _ -
32
The license applicant responded to the question in a letter dated
1/13/76 which stated in part "Volves DH-V4A and DH-V4B will be placed in
the normally open position. FSAR Figure 9-6 will be revised in
Amendment No. 48 to indicate this revision to the Decay Heat Removal
System. How?ver, as previously committed to and accepted by the NRC and
ACRS. power mst be oailable to these valves as they are required to be
throttled ir. cie- to split the decay heat (LPI) flow. The Low Pressure
Injection Systel is provided with a crossover line to permit one LPI
string flow of 3000 gpm to be split equally, thus providing a minimum of
1500 gpm flow to both core flooding injection nozzles simultaneously
should a core flooding line or one LPI pump fail. The LPI crossover
injection mode of operation is accomplished by opening the crossover
line. 3rovided with a two-way flow element, and remotely adjusting the
flow t1 rough the crossover line to 1500 by throttling the two el.ctric
motor operated valves DH-V4A and DH-V4B. Acceptance of this mode of
operation by the NRC is further exemalified in the staff's SER on page
6-13 and 6-14. Section 6.3.2 System Jesign. Therefore, valves DH-V M
~
and DH-V4B will be placed in the normally open position.
On 3/15/76 the applicant submitted FSAR Amendment 48 without indicating
the injection valves as normally open or changing operating procedu es.
Subsequently, an operating license was granted on 12/3/76 which
considered the information contained in amendments 1 through 49 as a
description of the facility. At no time since license approval had the
-
LPI injection valves been "normally open." nor has the FSAR ever shown
them as open. Pending further NRC review. the matter is unresolved. URI
50-302/97-12-09. " Failure to Normally Position LPI Injection Valves
Open."
c. Conclusions
The LPI injection valves are maintained ar mally closed. consitent with
the FSAR. However, in a letter dated 1/lm .. the liccnsee committed to
maintain the valves normally open and update the FSAR accordingly.
Those actions were never accomplisheu. The NRC will further review this
unresolved matter.
E8 Miscellaneous Engineering Issues
E8.1 As-Built Plant Discrepancy
During a simulator scenario observed by the team, an operator determined
that a control room HVAC fan control switch operated differently when
changing fan speed than 'n the actual facility. Subsequent follow up
identified that the switch in the simulator was consistent with the
approved schematic drawina and the switch in the facility was not
consistent with the drawing. 10 CFR 50. Appendix B. Criterion V.
Instructions. Procedures and Drawings, requires drawings be appropriate
to the circumstance. Having the drawing and switch reflect different
wiring configurations was a violation of that requirement. The licensee
initiateo PC3-C93-0161 and established corrective actions. The team
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
____ _ _ _
33
- reviewed the licensee's planned corrective actions for the PC and
determined that the root cause analysis was appropriate and the
corrective actions specified in the PC would adequately correct the
deficiency. The mis-wiring did not affect the ESF feature of the fan.
This licensce identified and corrected violation is being treated as a
Non Cited Violation. NCV 50 302/97-12-10. ' Wiring Error. consistent
with Section VII.B.1 of the NRC Enforcement Policy.
E8.2 (Closed) VIO 50-302/97-01-07: Instrument i. cop Uncertainty Set point
Calculation Assumptions Not Translated into Procedures
As discussed in section E.1.1.b.2 abwe. the licensee failed to identify
and correct calculations supporting 20P related set points as part of
the corrective actions for Violation 50-302/97-01-07. Consequently,
these cciculations contained the same type of errors. Violation 50-
302/97-01-07 is considered closed and the balance of the corrective
actions associated with this violation will be tracked as part of the
corrective actions for the violation identified in section E.1.1.b.2.
IV. MANAGEMENT HEETINGS
, X1 Exit Meeting Summary
The team leader discussed the progress of the inspection with licensee
representatives on a daily basis and presented the inspection results to
members of licensee management and staff listed below at an interim exit
on December 12. 1997 and at the conclusion of the inspection on January
9. 1998. The licensee acknowledged the findings presented.
At the final exit the team leader asked the licensee whether any
materials examined during the inspection should be considered
proprietary. No proprietary information was identified.
--
34
- PARTIAL LIST OF PERSONS CONTACTED
LICENSEE:
- J. Baumstark. Director. Quality Programs
- G. Becker, E0P Project
- M Collins. Operations Engineer
- J. Cowan, Vice-President. Nuclear Production
- R. Davis, Assistant Plant Director. Operations
- R. Grazio. Director, Regulatory Affairs
- S. Greenlee. Manager, Nuclear Operations Engineering
- B. Gutherman, E0P Project
- J. Holden, Site Director
- M. Kelly, E0P Project
- D. Kunsemiller, Manager, Nuclear Licensing
- J. Lind, Manager Nuclear Operator Training
- C Pardee, Director, Plant Operations
- W, Pike, Manager, Nuclear Regulatory Compliance
- D. Porter E0P Project
- K. Rass. E0P Project
- M. Rencheck Director Engineering
- T. Taylor. Director, Nuclear Training
- G, Wadkins, Licensing Engineer
- R.Widell,E0PProject
NRC:
- S. Cahill, Senior Resident Inspector
- G. Galletti. NRR
- P. Harmon, RII
- L. Mellen, RII
- J. Bartley, RII
- L. Reyes, RII. Regional Administrator
- J. Jaudon, RII. Division Director. Division of Reactor Safety
- W. Rogers. RII
- personnel present at the 12/12/96 interim exit
- personnel present at the 1/9/98 exit
LIST OF INSPECTION PROCEDURES USED
IP 42001 Emergency Operating Procedures
LIST OF ITEMS OPENED
50-302/97-12-01 VIO InadequM( Implementation 01 TMI Action Item E0P
Order.(Sections 03.1.b.3.(a) 03.1.b.4. 03.1.b.6.
03.2.b.2. 03.2.b.3(b). 03.2.b.4)
50-302/97-12-02 VIO Inadequate Corrective Actions (Sections
03.2.b.3(a). 03.2.b.3(b). E1.1.b.2)
- _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ . . _ _ _ _ _ ._ _ . - . _
)
'
35
50-302/97-12-03 IFI Enclosure 17/18 Interaction. (Section 03.2.b.5)
'
50-302/97-12-04 NCV Inadecuate External Leakage Surveillance
,
Procecure. (Section M3.2)
50-302/97-12-05 VIO Poor Calculations. (Section E1.1.b.3 and
E1.1.b.4)
50-302/97-12-06 URI Previous LPI Crosstie Safety Evaluations.
(Section E1.2.b.1)
50-302/97-12-07 URI Current LPI Crosstie Safety Evaluation. (Section
E1.2.b.2)
50-302/97-12-08 VIO Incorrect HPI Pump Purchase Order. (Section
- El.3)
,
50-302/97-12-09 URI failure to Normally Position LPI Injection
Valves Open. (Section E1.5)
- 50 302/97-12-10 NCV Wiring Error. (Section E8.1)
T
LIST OF ITEMS CLOSED
50-302/96-06-10 URI Justification for Removal of Thermo-Lag
Protection from Source Range Instrumentation.
>
(Section 08.2)
,
50-302/97-01-07 VIO Instrument Loop Uncertainty Set point
Calculation Assumptions Not Translated into
Procedures. (Section E8.2)
,
._ ., - e . - - - . . .- , . , - - -
36
' Appendix A
LIST OF DOCUMENTS REVIEWED
LIST OF INDUSTRY INFORMATION DOCUMENTS REVIEWED
ISA-S67.04. Part I. " Set points for Nuclear Safety-Related Instrumentation."
dated September 1994
ISA RP67.04. Part II. " Methodologies for the Determination of Set points for
Nuclear Safety-Related Instrumentation." dated 1994
NRC Regulatory Guide 1.105. " Instrument Set points for Safety-Related
Systems." Revision 2. dated February 1984
__ . LIST OF PROCEDURES REVIEWED
AI-400F. New Procedures and Procedure Change Processes for E0Ps. APs. and
Sup)orting Documents. Rev. 4
AI-402A, E0P Writer's Guide for Abnormal and Emergency Operating Procedures,
Rev. 8
AI-402C. AP and E0P Verification and Validation Plan. Rev. 04
Al-505 Conduct of Operations During Abnormal and Emergency Events. Rev. 02
AP-380 Engineered Safeguards Actuation. Rev. 20 & 22
AP-510. Rapid Power Reduction. Rev. 01. Rev. 01 Draft
AP-581. Loss of NNI-X. Rev. 07 Draft
AP-582. Loss of NNI-Y. Rev. 06 Draft
AP-770. Emergency Diesel Generator Actuation. Rev. 23. Rev. 23 Draft J.
Rev. 23 Draft 0
CP-149. Primary Coolant Sources Outside Containment Program Rev. 02
OP-404. Decay Heat Removal. Rev. 6, 8. 12, 22. 24, 26, 44, 48. 51. 56, 63,
66. 67. 68. 73. 74. 75. 78. 87. 99. 101, 102
OP-417. Containment Operating Procedure. Rev. 73
SP-306. Weekly Surveillance Log. Rev. 17
E0P-01, E0P Entry Conditions. Rev. 02. Draft Rev. 02 Draft
E0P-02. Vital System Status Verification. Rev. 04. Draft L
E0P 03. Inadequate Subcooling Margin. Rev. 05. Rev. 05 Draft P
E0P-04. Inadequate Heat Transfer. Rev. 04. Rev. 04 Draft T
E0P-05. Excessiver Heat Transfer Rev. 03. Rev. 03 Draft T
E0P-06. Steam Generator Tube Rupture. Rev. 05. Rev. 05 Draft F. Rev. 05
Draft H. Rev. 06
E0P-07. Inadequate Core Cooling. Rev. 04. Rev. 04 Draft J
E0P-08. LOCA Cooldown. Rev. 05. Rev. 05 Draft N
E0P-10. Post-Trip Stabilization. Rev. 03. Rev. 03 Draft M
E0P-12. Station Blackout. Rev. 02. Rev. 02 Draft J
E0P-13. E0P Rules. Rev. 03. Rev. 03. Draft J
E0P-14. Enclosure 1. SP0 Post-Trip Actions Rev. 02. Rev. 02 Draft T
E0P-14. Enclosure 2. PPO Post Event Actions. Rev. 02 Rev. 02 Draft T
E0P-14. Enclosure 5. MSIV Recovery. Rev. 02 Draft S. Rev. 02 Draft T
._ _ _ _ __
37
E0P-14. Enclosure 6, OTSG Blowdown Lineup, Rev. 02, Rev. 02 Draft R.
Rev. 02 Draft T
E0P 14. Enclosure 7. EFP 2 Management. Rev 02. Rev. 02 Draft S. Rev. 02
Draft T
E0P 14. Enclosure 8. MFW Restoration. Rev. 02. Rev. 02 Draft S. Rev. 02
Draft T
E0P-14. Enclosure 10. Alternate OTSG Feedwater Supply, Rev. 02, Rev, 02
Draft N Rev. 02 Draft T
E0P-14. Enclosure 11. EDG Load Management, Rev. 02 Draft R. Rev. 02
Draft T
E0P-14. Enclosure 13. High Pressure Aux Spray Lineup Rev. 02 Draft R. Rev. 02
Draft T .
E0P-14. Enclosure 14, Station Blackout Main Generator Purging. Rev. 02 Draft T
E0P-14. Enclosure 15. E0P Temperature Log, Rev. 02. Rev. 02 Draft 0. Rev. 02
Draft T
E0P-14. Enclosure 17. Control Complex Emergency ventilation, Rev. 02.
Rev. 02 Draft R. Rev, 02 Draft T
E0P 14. Enclosure 18. Control Complex Chiller Startup Rev. 02. Rev. 02 Draft
S. Rev. 02 Draft T
E0P-14. Enclosure 20. Boron Precipitation Control. Rev. 02 Draft T
E0P-14. Enclosure 21 RB Hydrogen Management. Rev. 02. Rev. 02 Draft P. Rev.
02 Draft T
E0P-14. Enclosure 24. Tables, Rev. 02 Draft L
EP-106, Loss of RC/RC Pressure, Rev. 8, 13, 16. 17. 20
LIST OF CALCULATIONS REVIEWD
M96-0035. Rev. O. Criteria for Termination of RB Saray
M95-0016. Rev. 2. BWST Swapover and Minimum Allowa)le Level
M93-0015. Rev. 1. Condensate Storage Tank Volume
191-0026, Rev. 2. CR-3 CFT Press /LPI Flow Evaluation
M95-0009. Rev,1. CR-3 Sump Solution pH Calculation -Report
188-0027. Rev. O. Responses to NRC Ouestions Regarding Tripping RC Pumps on
Loss of Subcooling Margin
191-0002. Rev. O. MU Tank Level loop Accuracy
M93-0056. Rev. O. LOCA RB Spray Sensitivity Study
184-0006. Rev. O. Analytical Justification for the Treatment of RCP During
Accident Conditions
190-0022 Rev. O,
191-0028. Rev. 1. FWP-7 Flow Indication
M93-0006. Rev.,O. RB Purge Dose Evaluation
E90-0023. Rev. 1. Evaluation for Containment Spray between pH 4.0 and 12.5
_ - - - - - .. . . . . - _ -
38
>
Appendix B
List of Acronyms Used
.
AB Auxiliary Building
ACRS Atomic Concerns and Reactor Safety
ADV Atmospheric Dump Valve
Al Administrative Instruction
ANSI American National Standards Institute
AP Abnormal Procedures
ATWS Anticipated Transient Without Scram
CFR Code of Federal Regulations
CFT Core Flood Tank
CHV Chilled Water Valve
CP Compliance Procedure
- CR Crystal River
CR0 Control Rod Drive
CXV Cross-tie Valve
DH Decay Heat
DHV Decay Heat Valve
ECC Emergency Core Cooling
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
EFIC Emergency Feedwater Isolatio,' Logic
EFWT Emergency Feedwater Tank
E0P Emergency Operating Procedure
ES Engineered Safeguards
ESF Engineered Safeguards Features
FSAR Final Safety Analysis Report
FWP- Feedwater Pump
HPI High Pressure Injection
HVAC Heating, Ventilating and Air-conditioning
IFI Inspector Followup Item
ISA Instrument. Society of America
LBLOCA large Break Loss of Coolant Accident
LOCA Loss of Coolant Accident
LPI Low Prersure Injection
_
LPIS Low Pressure Injection System
LRV Leak Rate Valve
MCC _ Motor Control Center
MOV Motor Operated Valve
MSIV Main Steam Isolation Valve
MSV Main Steam Valve
MVP Make-up Pump
MWt Megawatt Thermal
F
39
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Re ulation
NSS Nuclear Steam Supp y
NSSS Nuclear Steam Supp y System
OP Ooerating Procedure
OTSG Once Through Steam Generator
PGP Procedures Generation Package
PPO Primary Plant-0perator
PRC Plant Review Committee
RB Reactor Building
RCP Reactor Coolant Pump
SBLOCA Small Break Loss of Coolant Accident
SB0 Station Blackout
SER Safety Evaluation Report
SGTR Steal Generator Tube Rupture
SP Surveillance Procedure
SP0 Secondary Plant Operator
SR0 Senior Reactor Operator
SWV Service Water Valve
TBD Technical Bases Document
TMI Three Mile Island
TS Technical Specification
URI Unresolved Item
USQ Unreviewed Safety Question
UFSAR Updated Final Safety Analysis Report
VAC Volts - Alternating Current
VIO Violation
VSSV Vital System Status Verification