ML20207S377
| ML20207S377 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 03/10/1987 |
| From: | Bettenhausen L, Chung J, Florek D, Johnson W, Thomas Koshy, Kucharski S, Murphy K, Schnebli G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207S351 | List: |
| References | |
| TASK-2.K.3.03, TASK-TM 50-277-86-25, IEIN-84-69, IEIN-86-057, IEIN-86-100, IEIN-86-57, NUDOCS 8703190330 | |
| Download: ML20207S377 (75) | |
See also: IR 05000277/1986025
Text
. i
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
i
Report No. 50-277/86-25
Docket No. 50-277
License No. DPR-44
Licensee: Philadelphia Electric Company
Facility Name: Peach Bottom Atomic Power Station, Unit 2
Inspection At: Delta, PA
Inspection Conducted: December 8-19, 1986
Inspectors: -r /
Chun
,
Lead r En ineer
d
/ da
N
nhukhg 9UtM P 2/23 77
/
D'. J. Florek, Luad Reactor Engineer I dhte
h Y- 0
T Koshy",~ Reactor Engineer
Sb $Y
date
5'.
kl
Kucha'rifkT, Re
Sh
nt Inspector
Sb dat
Y
frtM' / __ J 7
K. Murphf, Tedhnigif1 pistant, /datt
Assistant Team Leader
Yh/
GT Schnetili, Reactor Engineer
$ ]/]lOdate
Yh ~
b
L.'Bettenhausen, Chief, Operations Branch, DRS
3A' S/87
date
Team Leader
Approved by: N 3//8/77
W. V. Johnston, Acting Director
~
date
Division of Reactor Safety
h
0
DO 5 7
--
F
m t ,
% g (.
- 8 I' \:, .
\ 4 .-
, >
t .
.c '
<
s, h
. >
, ,s,
" ' '
,t2
'
1
(. ' ,
g
, <
,,'
I
Y, ' i
,
j
j'
y t
u / , . . I'
Inspection Summary: Inspection on December 8-19, 1986 (Report No. 50-277/80-25)
See Executive Summary V i 'i
Results: One violation (failure .to provide continuous firewatch). One deviatton
(failure to test DC undervoltage _ relays). Four weaknesses (1) updatirg emergiocy
operatingprocedures;andresolvinghumanfactorsproblems;2)compNelyand ,
,,, ,
consistently labelling plant equipgent and insuring correct procedural;identifica- '
tion; 3) providing complete technical information such as AC atd DC,%ijtuit load
lists; and 4) maintaining and testing supporting equipment.
. .i
"
i
s
% P ,'
g.
'
t, .
9: ,,;
,
,i T.
p
t \
N; N
-
( 1
T
S.f, N
,
T ') )
Y
% ' l'
. :
1
'\
il
,1
\
\
,
!
1
\
1
.- ,
_
, , . _m , . -
-.
, ' (h ; J i: g
-
, ; \\ ,f- e
{ j '. _ h'
.
'N' )$l'
. ,
1
p(+g.s
v,
T .
-
'
t .-
l
)-
(4
'
- ' 'T -
) e . CONTENTS
'
y I'NSPECTION FEPORT 50-277/86-25
,\ .8 s. ).
1
,
NN 3 p s ,1
\
$ '\
,
9,. Page
y I' 0 EXECUTIVE SUMMA 3Y , '
1
iy a
,
'-
!
1
. s Fi.0 INTRODUCTION 2
s. t.
s
/
. (
t[' i .
y 2.1, Inspection Methodology 2
s
- 2.2 DRA g Used for Inspection 3
):
' \ +
.
i 2.3 . Selection of Accident Sequences & Inspection Areas 3
- 5 .y
- \ 2.4 Summary of Inspection Findings (with Section Index)
- 5
th N if0 ACCIDENT SEQUENCES inh 0-(VING PLA!1T TP.AN3IENTS WITH ELECT
'/3 t
4 POWER UPSETS U
7
y' '\' '
.
<
. 3.1, Sequences, Failures and Systems Considerations 7
- '
. , :
-
Yti 3.2 ,0ff site AC Power Supply 8
f
,
3.3 On-Site AC Power Supply / Emergency Diesel Generators 9
'
3.4 On-Site DC Power Supply 13 -
3
3.5 ' Supporting Systems. 16
i
3.5.1 ( Emy(rgency Service Water Systems (ESWS) 16-
\s
f
\ 3.5.2 4
Emergency Cooling Water System (ECWS)
\
19
$ a i ,
F
i l 43.5.3 ( Diesel Building Ventilation 21
3.5 Procedures and Operations Dealing with Electrical
[ Power Upsets 22
e
3.6.1 Loss of One or More Offsite Power Sources 22
3.6.2 Station Blackout 24-
13.6.3 Power Restoration 26
'\ ,-
t (
'i
>
,
k
,
I
,
4
e v-----w, -<,r,m-+--r-- --be-,. n .-,,--- +-,w-.-e-r-e,, ,wan --ww,--,----- , - -n, -p-,,- ,r-e---+-- , -,,g,-,,rnyn
-
--c,,,, ,en
- -- .. . . .
.
<
. .
. .
.
'
i
'
2
-
Page
l'
4.0 ACCIDENT SEQUENCES INVOLVING TRANSIENTS WITH CHALLENGES TO
CONTAINMENT 26
4.1 Sequences, Failures and System Considerations Including
Anticipated Transients Without Scram (ATWS) 26
4.2 Main Stea'm Isolation and Safety / Relief Valves 27
4.3 Containment Venting ,
34
4.4 Anticipated Transient Without Scram j (ATWS) 39
5.0 INSPECTION OBSERVATIONS REGARDING PROBABILISTIC RISK ASSESSMENT
l (PRA) 39
t
5.1 Human Factors 39
5.2 Reliability & Availability 41
"
6.0 ADMINISTRATIVE CONTROLS 42
6.1 Maintenance 43
'
6.2 Surveillance >
43
6.3 Quality Assurance ^and Quality Control 43
6.4 Modifications 44
7.0 PERSONS CONTACTED AND ME C M S HELD 47
7.1 Persons Contacted 47
7.2 Utility PRA Applications 48
APPENDICES
Appendix A - P.t;erures and Reports Reviewed
A.1 Administrative Control Procedures A-1
A.2 MSIV and SRV Documents A-2
A.3 QA Audit Reports A-3
A.4 Emergency Procedures A-4
A.5 System Procedures A-5
A.6. Surveillance Procedures & Completed Reports A-6
A.7 Maintenance Procedures A-7
A.8 Other Procedurs & Reports A-8
_ _ _ _ _ _ _ _
. .
3
Appendix B - Drawings Reviewed
B.1 Piping & Instrumentation Drawings 8-1
B.2 Electrical Drawings B-1
Appendix C - Initiating Events, Components, and Human Actions C-1
Selected for Inspection
l
.
',
,
. .
1.0 EXECUTIVE SUMMARY
A team inspection focused by Probabalistic Risk Assessment (PRA) was
conducted at Peach Bottom Atomic Power Station, Unit 2, from December 8-19,
1986. Accident sequences resulting from plant transients involving station
electrical power upsets and Anticipated Transients Without Scram (ATWS)
were examined in two ways. In one, the plant equipment needed to cope
with the accident sequence was physically inspected along with review of
its maintenance and surveillance. In the other, simulated performance of
,
)
emergency actions for the sequence by plant operators and support staff
members was observed by the inspector.
l Sequences involved loss of off-site power, loss of on-site AC power (Black-
!
out), loss of DC power, ATWS and supporting system operation (or failure).
Equipment included off-site power connections, apparatus providing normal
AC power, emergency AC power systen components, the DC power system, emer-
gency service and cooling water, ventilation systems, main steam relief and
isolation valves, high pressure coolant injection and containment pressure
control.
Overall, adequate emergency and operating procedures could be performed by
an experienced and knowledgeable staff with a very good understanding of
the procedures ard the hardware. Plant equipment is sufficiently reliable
to function as well or better than described in the PRA.
Two areas of weakness in procedures were human factors problems found with
some procedures in all areas reviewed and problems of integration of all
emergency operating procedures (E0P's) into a logical and consistent scheme.
The blackout procedure was event-oriented and not integrated into the symptom-
based E0P's and the containment pressure control procedures likewise were
not integrated into E0P's and were not logically ordered. The licensee had
plans to incorporate these event oriented procedures into the E0P format.
Operators were familiar with the procedures and were able to demonstrate
workability.
There was a lack of complete and consistent labelling and identification of
plant equipment; this contributed to some human factors problems. This weak-
ness has been known for some time and is being addressed by a major plant-wide
identification program, but it is not yet complete. While much technical data
is complete and readily usable, some important information was not present at
the site. Missing information involved "as-found" pressure relief setpoints
for safety / relief valves and most battery charger capacity test data. In
addition an up-to-date AC or DC bus load list was not available.
Surveillance testing to assure operability was generally very good. However,
weaknesses in the maintenance and testing of support systems were noted.
This included both preventive and corrective maintenance. The most signifi-
cant weakness was lack of documented maintenance and testing for the fans for
diesel generator, battery and switchgear rooms. Several other examples were
also noted.
. .
2
One violation for failure to provide a continuous firewatch while testing
- diesel generators with fire suppression disarmed and one deviation from *i
Final Safety Analysis Report commitments to test control room annunciation
from DC undervoltage relays were identified.
2.0 INTRODUCTION
This inspection was conducted by a team of NRC Region I and Region II
inspectors to examine aspects of Peach Bottom Unit 2 in the light of the
plant-specific probabilistic risk assessment described in the Reference
Plant Accident Sequence Likelihood Characterization: Peach Bottom Unit 2
(draft NUREG/CR 4550T. The report summarizes the accident sequences
selected, the ways that these sequences were probed and the conclusions
of the inspectors.
This section briefly describes the inspection methodology and the accident
sequences about which the inspection was structured. It ends with a summary
of the inspection results. The body of the report, Sections 3.0 through 6.0,
-
describe in some detail the equipment, procedures, and plant staff knowledge
examined to ascertain 1) the quality of hardware, software and personnel
knowledge in routine day-to-day operation, 2) the ability through emergency
procedures and staff knowledge to cope with and mitigate the accident
sequences examined and 3) the data to validate some of the PRA conclusions.
Later sections of the report document records reviewed and activities
inspected.
2.1 Inspection Methodology
The inspection was based on the results of the PRA study discussed in
detail in Appendix C. The study identified important plant equipment,
and possible inability of operators to respond and cope with events in
a timely or proper manner. The equipment and actions so identified
became the subjects of the inspection.
The inspection rationale was to evaluate the operational readiness of
the plant by evaluating risk significant hardware availability and the
capability of plant staff to conduct important recovery actions. Thus,
the effort focused on 1) programs and activities that assure the avail-
ability of the equipment selected, and 2) the ability of the station
staff to effectively perform actions to prevent or mitigate accident
sequences. Management controls, oversight by Quality Assurance and
Quality Control, training, and human factors engineering and effective-
ness of programs were also inspected to ascertain that the station
activities were performed in a manner assuring good performance.
A graphic presentation of the inspectic.n rationale is shown in Figure
2-1. The degree of equipment availability was qualitatively evaluated
based on the following criteria, as supported by the performance records,
programs, activities, initiatives, and observed conditions:
J
- . _
, - . . . - - , , , ,. - - - - - --
. .
t
.
,
1
HIGH ASSUhMNCE PRA Driven
.
ksentification or
Sofety Siv nicont
OPEhMTIONAZ, READINESS mmasons
Con Plant Equipment "A"O**E
Respond ? STArF ACTeoNS
'
I I I
Assess Assess Assess
Assess
Hardwa re Hardwore Plant Stof f
Administrative
Avoilobility
Challenges Controts Actions
Con Plont ,to
Respond *
l Simulation / Witnessing
Equipment Condition
Surveillance /Colibration of Piont Stof f Actions
(Plant Wolkthroughs)
+
System As Found Equipment
Lineup s Timeliness Operability /
Condition
Maintainobilit y
proc.esi r e. Adequor.y
Foilure Tech. Spec.
Normol/Abnoe rnal
Housekeep ag Environmentos
Dstec tion Requirements ,, g,,
,
Conditions
nowled4e/Ouo sific ations
Preventive / Corrective
Maintenance Sta tion
Oper a t ions
Foilure Recurrence Post-Mointenance Ef fective/ Prom pt
Prevention & Trending Correction
Testing
Environmentoi
Qualification
FIGURE 2-1 INSPECTION RATIONAL
- . ~ - ~ - . - - . . _ - - - . - . --
. .
l
3
measures to prevent equipment deficiencies or failures (preventive
maintenance, trending performance);
prompt detection of failures or deficiencies (surveillance); .
effective correction of such findings (corrective maintenance); '
verification of equipment operability (post-maintenance testing,
testing and calibration, and operational check-off).
The operation of plant systems and equipment identified in the selected
accident sequences was described by the plant staff during " event
simulations" conducted in the control room and equipment areas. The
operations were evaluated to ascertain that operators were familiar
with the plant equipment and the associated plant procedures during
normal, abnormal and emergency situations. The event simulations were
evaluated for the operator's ability to utilize control room or local
indications, to understand manual and automatic features under the
event situations, to use appropriate procedures and to operate equipment
manually and locally, including alternate train operations. A particular
inspection emphasis was to assure that proper emergency procedures
(both symptom and event oriented procedures) were available and capable
of being effectively used during the accident situations and under
stress. The procedures were evaluated for adequacy, technical accuracy,
clarity, and consistency.
2.2 PRA Used For Inspection
Peach Bottom Unit 2 was selected as the generic BWR design for analysis
in the Reactor Safety Study, WASH-1400, October 1975. As part of the
continuing research into severe accidents, the Peach Bottom Unit 2 PRA
is in the process of being updated by the NRC. Region I was provided
with a draft copy of the updated PRA, Volume 3 of NUREG/CR-4550. This
draft report formed the basis for the inspection. Questions remain
concerning details of the PRA and are subject to ongoing independent
re-evaluation by NRC contractors (e.g., the quantification of common
cause battery and diesel generator failures as well as the likelihood
of successful containment venting). Notwithstanding these questions
the results of the draft report were used. The final report may incor-
porate changes as a result of these re-evaluations but it is expected
that the hardware and human actions selected for this inspection will
still be evaluated as safety significant.
2.3 Selection of Accident S:;uence: 2nd Inspectien Are g
Ten dominant accident sequences and their related equipment failures,
human errors, and recovery actions account for the majority of risk.
An analysis was performed to provide the basic event importance involved
in 9 of the 10 sequences by the inspectors related to station blackout
and anticipated transients without scram (ATWS). Appendix C provices
the detailed results of the analysis. Two blackout sequence groups and
one ATWS sequence group form the basis for inspection as they address
most of the equipment failures and human activities identified. The
three sequences are as follows:
, -
- _ . . _
. .
4
2.3.1 Transients With Loss of AC and DC Sequence Group (TBUX)
-This group is characterized by transients leading to the loss
of all AC power as a result of coincident DC power failures.
The loss of DC power causes failure of the four emergency
diesels, High Pressure Coolant Injection (HPCI), and Reactor
Core Isolation Cooling (RCIC) systems which in turn result in
the loss of all core and containment cooling. Without the
restoration of AC and DC power within 30 to 40 minutes, the
primary system coolant inventory boils off and core damage
results. This is a fast paced accident with little chance of
recovery and focuses on common cause failure mechanisms involv-
ing the emergency DC system.
2.3.2 Extended Loss of Offsite Power with Battery Depletion Sequence
Group (TB)
This sequence group is characterized by transients leading to
a long-term loss of all AC power. Core cooling is initially
successful with HPCI or RCIC providing coolant injection until
about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> into the sequence. At that time the batteries
deplete and affect the ability to continue operation of these
systems. Without power recovery within 2-3 hours of battery
depletion, core damage results. This is a slow paced accident
scenario directing attention to a number of potential hardware
'
and operational problems such as the loss of offsite power
and its recovery, the common cause failures of diesels and
their recovery, the loss of important support systems such as
Emergency Service Water, and the operator actions required to
diagnose the situation, establish core cooling under loss of
AC conditions, and recover electrical supplies.
2.3.3 ATWS With Closure of MSIV Sequence Group (TCUX)
This sequence group is characterized by an ATWS with either
prompt MSIV closure or MSIVs initially open but with subsequent
closing. This isolates the reactor system under high power
conditions resulting in a rapid increase of pressure and temp-
erature conditions within the containment. The standby liquid
control system should be started by about 4 minutes, but the
sequence assumes initial HPCI failure and operator failure to
rapidly depressurize the vessel to allow use of low pressure
ECCS and this leads to a rapid core damage event. Subsequent
containment failures may or may not occur depending on the
success or failure of containment venting. This group of
sequences directed the team's focus on ATWS and venting emer-
gency procedures as well as the availability of HPCI.
,
, .
5
!
2.4 Summary of Inspection Findings (with Section Index)
For each portion of an accident sequence selected for inspection, the
operati.;g, emergency, maintenance and surveillance procedures and data
obtained in their prior performance were reviewed. Often, individuals
responsible for performance of the procedures were observed and ques-
tioned during their actual or simulated performance of the procedure.
The summary of these findings is discussed in this section; the section
reference to more detailed discussion concludes each point.
Procedures reviewed were found to be adequate for the purpose or intent
to which they were developed. The quality of procedures ranged from
excellent emergency operations (TRIP) and certain surveillance test
procedures to barely adequate maintenance and surveillance procedures;
specific discussions are found in Sections 3.6, 4.3, 4.4, 6.1 and 6.2.
Specific deficiencies of note are summarized in Table 2-1. Those
relating to procedures include:
Lack of guidance, inappropriate or outdated acceptance criteria,
decision-making criteria and timing information. This is most
apparent with Station Blackout (E-28) and Containment Venting
Procedures (3.6.2, 4.4) and is regarded as a weakness by the
inspection team.
Human factors problems. These were found with some procedures
in all areas (5.1).
Pressure switch calibration procedure incomplete (3.5.1).
The station staff members using the procedures were sufficiently familiar
with plant systems and equipment to work through the procedural difficul-
ties in time. A large number of station staff members were involved with
the inspection; without exception, their knowledge was very good and was
commensurate with their experience and duties.
Plant equipment was found to be very reliable and, in general, well main-
tained and adequately tested. An aggressive and knowledgeable approach
to diesel maintenance and good battery and AC switchgear maintenance
were observed. The reliability is discussed in Section 5.3. For speci-
fic equipment inspected, the reliability was as good or better than the
PRA assumption. In one area, unavailability of diesel generators due to
maintenance, the PRA value of 1% was more optimistic than the 3% plant
data (5.3.2.). However, a weakness was identified in the maintenance
and testing of the support systems. Included as part of this weakness
are:
No test or maintenance of DC undervoltage annunciator relays
(Deviation) (3.4.3)
No inclusion of substation undervoltage relays in trouble alarm
annunciation (3.2.2)
. . _ _
_
- . . _ - - _
_ - - - - - - - - - - - - - - - - -
.
7A~ BLE~ 2- 1 SUMMARY OF F//VDHVGS .
Un resolved Deficiency Proposed Licensee Report
liern No.+ Corrective Actions Section
- North Substa tion battery undervoltage Restore North Substation 3.2
I circuit not wired to trouble alarrn in alarm & verify South
control room Substation clarm
- EDG observations; rnost corrected Corrected during inspection 3.3
l prior to Exit Meeting: or correction in prog ress
+ loose electrical conduits
+ components mislabeled or with
missing labels
n.
+conh 'ol ' cabinets: heaters off and
esose party inside
- oil level requirements not on
checkoff lint
+EDG inaccurate tube oil P&lD
-
Low gas pressure in emergency Assure tirnely correction 3.3
transformer not corrected in future
1 inconsistent labeling, examples: Review as part of plant
+EDG lube purnp la beling prograrn (CEMS) 3.3
+4KV Switchgear Rooms and rewrite EOPs 3.5.1
+ Trip Proced ure T- 101 5.1.3
2 EDG operator leaving diesel room LER written, EDG surveillance 3.3
with Cardox systern :" proced'Jre modified, and
(VIOLATION) operators warned
-
Battery observations: Procedure revisions or 3.4
- Affects of equalizing voltage evaluations in progress l
on DC coito {
+FSAR revisio n, higher float voltage i
+ P roce d . S.8.5.A. apply to Unit 2
- Reco rd battery charger capacity
+ 277/8 6- 25-XX PB25
.
TABLE ~ 2- 1 SUMMARY OF F7ND/NGS (CONT) .
U nres olved Deficiency Proposed Licensee Report
liern No.+ Corrective Actions Section
-
Battery observations (cont.): Procedure revisions or 3.4
+ Record equalizing voltage evaluations in progress
- lEEE Std. 450 comrnitments
3 AC & DC bus load growth, Prograrn under 3.4
no formal prog rarn development
4 DC undervoltago relays, no Satisfy FSAR 3.4
testing or rnaintenance Section 8.7.4.2
(DEVIATION)
5 incornplete pressure switch Modify procedure 3.5.1
calibration proced ure
6 No periodic visual inspections Periodic underwater 3.5.2
of ultimate heat sink sluice examinations will be
gates conducted
7 Lock of maintenance docurnentation Fan maintenance & 3.5.3
& inadequate testing of EDG. supplemental / standby fan
battery, & switchgear roorn fans testing will be initiated
8 Station Blackout Procedure Updates to be rnade 3.6.2 &
E-25 & Cont. venting proced u res part of EOPs 4.3.3
require updating
9 SRV as-found set points not Method for documenting 4.2.1
being recorded or ovaluated & evaluating set points
10 volve stroke tirne . based on Procedural changes 4.2.3
light-to-lig ht not under review
contact-to-contact
11 Unrestrained spare / grounding Restrain or rernove 3.3
breakers in switchgear rooms
-
30 day LCO of two EWS pum ps NA - Under N R C review 5.2.4
appears too liberal
+2 7 7/8 6-25-XX PB26
_ _
. .
6
Various problems in Emergency Diesel Generator (EDG) Rooms such as
loose electrical cables, de-energized control cabinet space heaters,
and loose parts inside control panels (3.3).
Various problems with the emergency busses such as unrestrained
large objects in the switchgear rooms and low gas pressure in
safety transformers (3.3), lack of testing on low battery voltage
annunciation circuit (3.4).
Lack of recorded maintenance and testing for EDG, battery, and
backup switchgear room fans (3.5.3).
Implement revisions to procedure to preclude "short-stroking"
motor operated valves (4.2.3)
Service water sluice gates not inspected underwater (3.5.2)
A general weakness was noted in a lack of consistency, lack of labels,
inadequate or confusing labelling of plant equipment and its identifi-
cation in procedures. This is a widespread problem which is being
addressed in part through a plant program now well underway. There is
much to be done to complete the program and assure consistent use of the
label names in procedures and plant documents. Specific problems are
discussed in Section 3.3, 3.6.2, 4.4 and 5.1.
Another area where weakness, as well as some strength, was found was in
technical documentation. Failure data, reliability information, mainten-
ance and surveillance records, procedures, drawings and technical manuals
were readily retrieved and made available to the inspectort. Some speci-
fic technical information regarded as important to the aims of this
inspection was not available, specifically:
No current AC or DC detailed load lists were available (3.4). This
made judgements on battery or bus availability difficult when loads
were simulated to be switched on or off.
Safety / Relief valve as-found set point data was incomplete (4.2.1).
Battery charger capacity test data was sparse (3.4).
Some technical issues not yet resolved by the station staff include a
review of valve stroke timing and maintenance procedure implementation
to assure compliance with the ASME Code (4.2.3) and implementation of
IEEE Standard 450 for battery maintenance and testing (3.4).
Inspectors who previously visited the Peach Bottom site observed that
plant housekeeping had greatly improved. The power block and equipment
there were clean and well maintained. Housekeeping improvements,
particularly in the EDG rooms, were noted during the inspection. Two
exceptions were housekeeping in the 13 KV switchgear rooms and as also
described above seismically unrestrained equipment, principally spare
and ground circuit breakers, in all of the switchg"ar rooms.
. .
7
Human performance in many aspects was assessed during this inspection.
As stated previously, station staff members were sufficiently familiar *;
with the plant to overcome procedure deficiencies. With the exception
of performance as firewatch while also conducting diesel generator test-
ing (violation; 3.3), individuals performing operations or surveillance
tasks were observed to adhere to procedures and perform in a well-
qualified manner.
In summary, existing procedures can be at;omplished by experienced and.
Knowledgeable staff members to deal with the accident sequences examined
through this inspection. Plant equipment is sufficiently reliable to
function as well or better than described in the PRA. One violation of
procedure and one deviation from commitments were identified.
3.0 ACCIDENT SEQUENCES INVOLVING PLANT TRANSIENTS WITH ELECTRICAL POWER UPSETS
As discussed in Section 2.3, this group of sequences is initiated by trans-
ients. The sequences then propagate in one of two ways - a fast paced
accident sequence resulting from coincident failure of all DC power with
subsequent failure of all AC power from loss of DC control and logic power,
failure of coolant injection systems such as HPCI and RCIC from the same
cause and resultant loss of core and containment cooling and a slow paced
sequence resulting from loss of all AC power and gradual deterioration until
batteries are depleted about six hours after initiation. In the former
sequence, common cause failure of all four safety related batteries is necess-
ary for the coincident loss. As discussed in this section, common causes
were sought; only the unlikely loss of cooling / heating to all four battery
rooms was identified. In the latter sequence, two aspects become important.
One is recovery of offsite AC power; this is discussed in Section 3.6.3.
The other is common cause failure of the onsite AC power sources - the
Emergency Diesel Generators (EDG's). The PRA treats Peach Bottom as a two
EDG plant. As detailed in Section 3.3, 3.5.2, and 5.2, there is good reason
to consider Peach Bottom as a plant with three EDG's for PRA analysis. Never-
theless, common cause failures of EDG's have occurred and were sought in the
course of this inspection and are discussed in Section 3.3. This portion of
the report concludes with results of the simulations of situations involving
various partial and complete power losses discussed in Section 3.6.
3.1 Sequences, Failures and Systems Considerations
In these electrical power upsets, the primary systems to examine are
offsite AC power, onsite AC power and onsite DC power. In order to
assure that these systems can perform their intended functions reliably,
some supporting systems are needed. For reliable provision of off-site
power, the control and logic provided by substation batteries is needed.
For operation of the onsite EDG's, provision of fuel oil, cooling water,
starting air, room cooling and combustion air and DC control and logic
power is required. Inspection of these systems, their simulated opera-
tion in emergencies and their maintenance and surveillance testing is
detailed in this portion of the report.
. .
8
3.2 Offsite AC Power Supply
- i
The loss of offsite power was identified by NUREG/CR-4550 as the major
initiator for two accident sequences of concern. The inspection object-
ives were to review reliability of offsite power sources and their
ccinection to station emergency electrical systems and to assure station
personnel are capable of recovering from postulated equipment failures.
One source of offsite electrical power for Peach Bottom normally is fed
from two independent 500 KV sub stations which are 3,000 ft apart.
Each substation is equipped with dedicated DC batteries (with a charger)
sufficient to operate the breakers despite a substation blackout.
There are four major transmission 500 KV lines that feed into these
substations. Moreover, the two substations are connected with two tie
lines which remain connected under normal conditions. A second source
comes from the 220 KV grid and nearby hydroelectric generating stations.
This arrangement offers a very reliable source of offsite power to both
Peach Bottom units.
The offsite power sources reach the plant location at two 13KV substa-
tions - one through overhead transmission and the other through under-
ground feeder cables. The two separately fed 13KV substations are
located on opposite sides of the plant. Each substation is capable of
feeding any of the 4 safety buses in each Peach Bottom unit. Each feed
from each 13KV substation supplies Emergency Auxiliary Transformers
which are located near the power station, but physically separated.
These transformers step down the voltage to 4KV and supply the emergency
buses. The normal configuration feeds the even numbered buses from one
transformer and odd numbered buses from the other transformer. When
one of the off-site power sources is not available, the licensee runs
and loads the diesel generator that is redundant to the available off-
site source, thus avoiding a plant trip due to a minor power interrup-
tion. This activity is within the requirements of the Technical Specifi-
cation. There are no electrical interlocks preventing either of the
start up sources from feeding any of the safety buses in either unit.
Under proper administrative control, this a versatile feature which
accomodates random breaker, cable and transformer failures. (See
Section 3.3 for generator cross connect capability which offers an added
flexibility for assuring power on safety buses). There is also a control
logic scheme for safety buses which permits only one transfer from one
startup to the other startup source before transfer to the diesel genera-
tor power.
The inspector reviewed the maintenance program for transformers,
breakers, protective relaying and the 500KV substation DC system.
The licensee has instituted a scheduled maintenance program on these
devices on a reasonable frequency and no discrepancies were identified.
The inspector walked down the major components at the 500 KV North
Substation. The licensee is in the process of replacing the 500-220 KV
auto transformers after a fire in April,1986. The relays and switch-
gear were clean and well maintained.
. - . . .
. .
9
The inspector witnessed a scheduled performance test on the DC battery
at the North Substation. The test was successful and no anomalies were
identified.
During the maintenance of the battery charger at the North Substation,
it was observed that the DC undervoltage alarm circuit was not wired
to the general trouble alarm which is annuniciated at the control room.
The licensee has agreed to restore this feature for the North Substation
and verify this feature at the South Substation also. Lack of this
information at the control room can delay prompt maintenance of the
substation DC system which is required for the operability of the
circuit breakers in the substations.
3.3 On-Site Emergency AC Power Supply / Emergency Diesel Generators
The emergency diesel generators provide on-site redundant sources for
emergency AC power in event of loss of normal AC power. There are four
emergency diesel generators to supply emergency power to both Units 2
and 3. Each emergency diesel generator can be connected to one Emergency
AC 4 Ky bus in Unit 2 and one Emergency AC 4 Ky bus in Unit 3. Normally
power to these buses is supplied from one of two Emergency-Auxiliary
,
Transformers aligned such that half the buses are fed from one trans-
- former and half from the other. Should a supply from one Emergency-
Auxiliary Transformer be lost to an Emergency AC 4 Kv bus, a single
'
automatic transfer to the other Emergency-Auxiliary Transformer would
occur. Should both supplies to an Emergency AC 4 Kv bus be lost, the
associated emergency diesel generator would automatically start and
l supply power to the Emergency AC 4 Kv bus. The dependency of these
emergency diesels upon DC power, cooling water, ventilation and other
support systems is clearly highlighted in PRA studies and discussed in
other sections of the report. The failure of one emergency diesel
engine-driven electric generator while another was out for maintenance
or the possibility of multiple diesel failures due to a single root
cause were identified in NUREG/CR-4550 as significant contributors to
the blackout sequences. For this reason, the inspector focused on
emergency diesel generator availability with emphasis on candidate
common cause failures. Recovery actions for starting a previously
failed diesel were also addressed.
The following plant areas and components of the on-site AC power supply
and emergency diesels were inspected:
--
Major electrical emergency AC busses
--
Relay Room
--
Control Room
--
Emergency Diesel Rooms E-1, E-2, E-3 and E-4
--
Starting Air Systems
--
Lube Oil Systems
--
Air Coolant and Jacket Coolant Systems
--
Control Panels
--
_ .
- _ _ . _ _ _ _ _
-_ . . .
. .
10
Visual inspection of these areas assessed general condition of the
equipment, as built location, proper identification, ambient environ- i
mental conditions, accessibility for maintenance, and station adminis-
tration controls related to housekeeping and fire prevention.
The incpector witnessed licensee performance of surveillance tests of
the Emergency Diesels to verify compliance with Technical Specifications
requirements and procedural controls. Test witnessing also provided a
performance based assessment of station perronnel activities during the
surveillance tests.
The inspector requested and observed licensee personnel performance of
simulated emergency procedures for startup of the diesels from various
locations. The inspector assessed the ability and competence of the
plant personnel in performing the required actions.
During the week of December 8, 1986, the NRC inspector made several
observations:
E-1 Diesel General Room
--
Loose electrical cable to air start solenoid valve
--
Control panel space heater off - indication of contact rusting
--
Labels missing from several components
!
'
--
ESW Outlet Test Tap (HV0-33-10901A) has cap missing
--
Mis-labeling on Remote Skid
--
DC feed panel is mis-labeled
E-2 Diesel Generator Room
--
Loose electrical conduit to air start solenoid valve
--
Air leak from the Air Start System
--
Labels missing from several components
--
ESW Outlet Test Tap (HV-0-33-10901B) has cap missing
--
Mis-labeling on remote skid
--
Control panel space heater off
--
DC feed panel is mis-labeled
E-3 Diesel Generator Room
--
Labels missing from several components
--
Mislabeling on remote skid
--
Control panel space heater off
--
Loose parts inside control panels
--
DC feed panel is mis-labeled
E-4 Diesel Generator Room
--
Labels missing from several components
--
Mis-labeling on remote skid
--
Control panel space heater off
--
DC feed panel is mis-labeled i
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. .
11
During the visual inspection, the inspector used the P&ID as an aid in
the process of locating valves. During this process it was noted by *;
the inspector that the P&ID for the lube oil system had two errors.
The pre-lube oil pump suction block valve was missing from the P&ID
and the P&ID shows a check valve on the discharge side of the standby
circulation pump which does not exist.
By the end of the inspection period, the licensee corrected the majority
of these inspection findings and was in the prc ..s of ravising the P& ids
to show the correct valve lineup.
The visual inspection verified in a number of instances that diesel
generator components had inconsistent designations. For example, a
name of a pump shown on the P&ID, labeled on a control panel, and the
labels on the pump itself were different as: lube oil pump, B lube oil
standby pump, and circulating pump. This labeling inconsistency is one
example identified to the licensee as an open item requiring future
inspection by NRC. The inspector stated that the name of a component
in a procedure, on control / instrumentation panels, on P& ids, and on the
component label should be identical to avoid confusion and error. The
licensee is in the process of upgrading the labelling of plant equipment
(CEMS program) and agreed with the need to assure that procedures and
other documents consistently identify the recently labelled equipment.
This is an Unresolved Item (277/86-25-01) and is discussed further in
later sections of the report.
The NRC inspector on two occasions requested licensee staff members to
simulate an emergency start of the diesels from several locations. In
each case the staff members showed adequate knowledge of the system and
the ability to start the system from either the control room or two loca-
tions in the Diesel Generator room (skid and control panel). No viola-
tions were identified.
On December 10, 1986, two NRC inspectors witnessed the performance of
surveillance tests for the E-3 and E-4 diesels. The tests were observed
from both the control room and diesel rooms. The inspector noted that
the plant operator (P.O.) turned off the Cardox system when entering the
diesel room. This was done for safety of the operator while in the
diesel rooms, in accordance with normal plant procedures. The tests on
E-3 and E-4 diesels were performed in accordance with the procedures and
the personnel performing the test were knowledgeable of the system.
However, it was noted that at approximately 1:00 a.m. during diesel
testing, the operator, who was also the designated fire watch, left the
diesel room (with the Cardox system off) to make a telephone call.
On December 16, 1986, the inspector witnessed the performance of surveil-
lance tests for the E-1 and E-2 diesels. At approximately 12:45 a.m.,
the operator was found outside the E-1 diesel room, while the diesel was
running and the Cardox system off.
-
. .
12
The above two occasions in which the plant operator left the diesel room
with the Cardox system off constitutes a violation, being contrary to the ' i
following:
Technical Specifications 3.14.B.4, paragraph a. states, in part, that
a continuous fire watch with back-up fire suppression equipment for an
unprotected diesel generator room is required within one hour. Station
administative procedure A-12.1, paragraph 2.1.3, requires that a dedi-
cated Technical Specification firewatch must be posted within one hour
after a Cardox System switch in a diesel generator room in placed in the
" defeat" position. Procedure A-12 in paragraphs 7.2.3 and 7.2.4 speci-
fies Technical Specification firewatch as an individual having "no job
related duties other than firewatch duties" (Violation 277/86-25-02).
Also, during the performance of the surveillance tests, the inspector
noted that the oil level on both the governor and generator on the E-1
diesel were below the scribe marks on the indicators; for the E-2 diesel,
only the generator oil level was below the scribe mark. When the P.O.
was questioned if this condition was acceptable, he was unsure. It was
later discovered through questioning by the inspector that even though
the diesel can run with oil levels below the scribe mark, it is not
recommended by the manufacturer. The licensee agreed to change the
procedure to check the oil levels during diesel operation and marked up
proposed procedure changes were reviewed by the inspector.
Surveillance procedure ST 11.6-2 D/G Simulated Auto Actuation and Load
Acceptance for Unit 2, test performed 6/13/85 was reviewed. The test
satisfied the test criteria.
The Walkdown of the major electrical emergency AC buses in the switchgear
rooms and at the relay room revealed that the protective relaying, relay
compartments and motor control centers were well maintained. However,
the inspector noted that spare / standby breakers and grounding breakers
mounted on rollers were stored in switchgear rooms A, B, C & D and
13 Kv switchgear rooms. These heavy pieces of equipment were not secured
and could incapacitate the safety related electrical buses during a
seismic event. This item will remain unresolved pending licensee action
to either restrain the objects or remove them from the switchgear rooms
(277/86-25-11).
The licensee has a scheduled maintenance program for safety related
electrical components. The inspector witnessed the undervoltage func-
tional test on 4 Kv bus E-32 per station procedure ST.12C Revision 2.
The relays functioned within the acceptance requirements and no discre-
pancies were observed.
On December 17, 1986, the inspector reviewed the operator walkdown sheets
for "Z" shift. The inspector noted that the gas pressure readings on
safety transformers No. 234 and No. 434 were recorded as out of the
stated acceptable range on three consecutive days. The inspector veri-
fied the readings on December 17, 1986 to be 4.2 psig and 5.5 psig for
-. - -- -
- _ - - - _ .
.. .
13
transformers No. 234 and No. 434 respectively. The acceptable value is
between 6-10 psig. The inspector inquired if any corrective action had g
been taken and was informed by the licensee that none had been initiated.
Subsequent to the inspector inquiries, the licensee initiated corrective
action. The inspector noted that the safety transformers were the sub-
ject of a violation issued in inspection report 50-277/86-09.
The examples cited above contribute to a conclusion that improvements
can be made to preventive and timely corrective maintenance practices
in this area. While the system or component performance in this area
was demonstrated to meet acceptance criteria, such observations as loose
electrical cables, de-energized control cabinet space heaters, missing
test caps, loose parts inside control panels, unrestrained large objects
in switchgear rooms and noted low gas pressures in safety transformers
lead to a conclusion of a weakness in maintaining supporting equipment.
3.4 On-site DC Power Supply
The safety objective of the station batteries is to supply all normal
and emergency loadt for the 1257 and 250V DC power. In case of a sta-
tion blackout, the DC battery system is required for the functioning
of safety or accident mitigation systems such as High Pressure Core
Injection (HPCI) Reactor Core Isolation Cooling (RCIC) and Automatic
Depressurization System (ADS) and starting control and logic power for
the Emergency Diesel Generators. The DC System is also relied upon to
provide essential monitoring and indicating functions. Based on NUREG/
CR-4550 the inspection focus was on battery availability with emphasis
on possible common cause failure which might affect several batteries.
The DC System is divided into two divisions. For each unit, Divisions
I&II have two 125V Batteries, 58 cells each, manufactured by Exide
(type GN 23). These batteries are located in separate rooms and mounted
on seismically qualified racks. New batteries were installed in Units
2 and 3 during the course of the last two refueling outages.
The batteries in Division I have a dedicated battery charger powered
from a safety related motor control center for each battery group.
Significant loads on this division are RCIC valves and logic power,
E-1 Diesel generator controls, emergency auxiliary switchgear relays
and one of the ADS power supplies.
The batteries in Division II have a dedicated battery charger for each
battery group powered from two different safety related motor control
centers. The significant loads on this division are HPCI valves and
logic power, E-3 diesel generator controls, emergency auxiliary switch-
9 ear and relays and one of the ADS power supplies.
The inspector walked down the Division II battery system. Using the
calibrated instruments from the licensee, random battery cell voltages,
specific gravity and float voltage were measured. These values were
compared against the acceptance values in the following procedures and
found to be acceptable.
- - _
i
. .~ j
i
l
14
-- ST 8.3 Station Battery Quarterly Check, Rev. 11
-- ST 8.5-2B Unit 28 125V Battery Service Test, Rev. 4
-- ST 4-2 Battery Discharge Performance Test, Rev. O
The maintenance department has a program to collect and trend data
collected by the above procedures. The licensee is in the process of
upgrading the battery maintenance procedures to incorporate provisions
of IEEE Standard 450 in response to comments from a recent INP0 audit.
The inspector made these observations following his review:
1. In the light of the extensive number of DC coil failures, it appears
that the DC Equalizing Voltage may be influencing the service life
of the DC coils. (See Section 4.2). The licensee has agreed to
evaluate the susceptibility of the DC coils for the overvoltage
conditions resulting from the equalizing voltage.
2. The newly installed batteries need a higher float voltage than
the. previous batteries. The licensee agreed to revise FSAR
Section 8.7.3 to show 2.26 V per cell as the equalizing voltage.
3. The station battery weekly check procedure ST 8.2, Rev. 9, refer-
ences another procedure S.8.5.A for equalizing the battery charge,
but this procedure presently applies only to Unit 3. The licensee
agreed to correct this discrepancy.
4. Presently, the capacity of the battery charger is not being tested
unless corrective maintenance is performed on it. The licensee has
included the battery charger maintenance procedure M 57.4, Rev. 3
into the maintenance schedule and agreed to revise the procedure to
document charger capacity during each refueling outage.
5. During the battery charger maintenance step 2.7 of M-57.4, Rev. 3,
the equalizing voltage is adjusted, but no readings are documented.
The licensee has agreed to revise this procedure to document the
as-found and as left values for equalizing and float voltages and
to provide acceptance values for these.
6. The licensee in response to INP0 findings is revising all the
battery maintenance procedures to include the requirements of
IEEE Standard 450 of 1980 or the forthcoming revision of 1987.
The revision will include:
a. Increasing the acceptance value of battery cell voltage to
2.13V or better,
b. Generating corrective actions when battery cell temperatures
deviate more than 5 F during a single inspection, and
c. Providing an equalizing charge when the electrolyte density,
corrected for temperature and level, of all cells drops more
than 10 points from the average installation value.
- _-.
. .
15
During the review of the design calculation of the DC battery, the
inspector noticed that the design margin on Batteries B & D were
only 3% as documented in Modification N0: 1048. The licensee later
-furnished a revisien to the calculation stating that the margin is
23% due to the selection of a superior type of cell for installa-
tion. During this inspection, the licensee was unable to identify
a program through which load additions on the DC electrical buses
are evaluated for their influence on load capacity, short circuit
rating, interrupting capacity, and relay coordination. Though this
matter was addressed for the DC battery, the concern extends to
AC buses also. Load additions without an up-to-date consideration
of static and dynamic effects, protection schemes and adequate
review of changes can significantly influence the availability of
the safety buses (see IE Information Notice 86-100). This item
is unresolved pending NRC receipt and review of a licensee program
for defining existing loads and the control of load growth, with
supporting calculations (277/86-25-03).
The licensee has installed DC undervoltage relays on 2 motor control
centers and 2 distribution panels in each division of the 250/125V
DC system. These relays are connected to control room annunciation
to indicate a low voltage in the DC system. These relays perform a
critical function to warn the operator about the degradation of
DC voltage. In a station blackout scenario, the function of these
relays is significant in informing the operator of DC voltage
adequacy and battery depletion.
The licensee committed to providing low battery voltage annuncia-
tion in FSAR Section 8.7.4.2, Rev. 4 dated January,1986, by the
statement " Low Battery voltage is annunciated in the main control
room". No record of a test of this annunciation could be produced.
A test plan was developed and conducted during the inspection.
The inspector witnessed the test performed on December 19, 1986
on the undervoltage relay mounted on MCC 20D12. As per the DC
system abstract, the setpoint of this relay is 240 Volts, but annun-
ciated at 139V and 162V in two attempts, thereby failing to perform
its intended function. The commitment in FSAR Section 8.7.5 states,
"The system is tested and inspected as required during the life of
the plant to demonstrate its capability to provide power to the
safety-related leads". Contrary to the above, the 'icensee had not
performed any testing or maintenance on DC undervoltage relays to
confirm the capability of he DC bus to provide power for the
safety related loads. This is a deviation from the FSAR commitment
(277/86-25-04).
The inspector had no further observations or questions.
. .
16
3.5 Supporting Systems
- i
3.5.1 Emergency Service Water System (ESWS)
NUREG/CR-4550 identified the ESWS to be safety significant
because it provides cooling water to the four emergency
diesels. The failure of this cooling function during a loss-
of-offsite power event would result in diesel shutdown from
overheating and subsequent loss of all AC. In addition to
this PRA identified function, other cooling functions related
to ECCS room cooling and ECCS pump cooling were also inspected.
The' inspection objec+ive was to evaluate the equipment avail-
ability and plant staff ability to recover from postulated
system failures.
The two ESW pumps, associated valves and pressure switches
located in the inlet structures were inspected. The Emer-
gency Cooling Water (ECW) pump, associated pressure switches,
breakers, and valves located in the emergency cooling tower
structure, as well as the pond discharge valves, booster pumps,
and associated instruments located in the emergency diesel
generator (EDG) building were inspected. No adverse conditions
were noted; housekeeping in all areas was acceptable.
The startup of the system was observed in the control room by
the inspector. The system is routinely started and run for
approximately five hours per week as part of diesel generator
testing. In two separate interviews, control room operators
were asked what their actions would be if pumps failed to
start, or if critical valves did not open. Operation action
in the case of failure of the pressure switches involved in
auto starting of the standby pump in the event of failure of
the operating pump, as well as the failure of MOV-0841 (ECWP
discharge) were investigated.
In all cases, the operators knew what indicators to look for
and what action to take both in the control room and in the
plant in order to recover from the postulated failures. In
addition to the control room operation, in plant recovery
actions were simulated by a plant operator (P.O.). These
included the opening of MOV-0841 via local breaker operation,
local start of ESW and ECW pumps and the energization and
closure of MOV-0493 (normally open and de-energized as a result
of Appendix R concerns). The communication between the P.O.
and control room via phones and radio were found adequate.
Emergency lighting and portable lighting appeared acceptable
in the applicable areas. Access to all areas was acceptable,
with the exception of security key designations discussed
below. The P.O. demonstrated acceptable kncwledge for locating
and operating the equipment. One significant human factor
.
. ..
17
deficiency became evident during these simulations. In order
to locate.a specific circuit breaker cabinet the P.O. is given t
the emergency bus designator such.as E-12 or E-23. However,
~
the switchgear rooms are labeled Unit 2 A&C, Unit 2 B&D, etc.
No indication of the buses that are in the rooms are evident.
During the simulation, the P.O. entered the wrong switchgear
room; however, once inside he immediately realized his mistake.
Thus is another instance of inadequate or inappropriate label-
ling, identified as an unresolved item in paragraph 3.3.
Part of the simulation checked whether the switchgear rooms
could be opened in case the security system was affected by
the loss of offsite power. Switchgear room keys were available.
However, the keys to the switchgear doors were labelled by yet
another designation system (e.g...the Unit 3 B&D switchgear
room is designated as the South East 3 Switchgear). The
licensee has committed to improve the labelling of the switch-
gear rooms-and-simplify the access key concern by reducing the
number of keys and providing more appropriate designations.
The inspector had no further observations.
The licensee provided Nuclear Plant Reliability Data System
(NPRDS) data and CHAMPS data on the'ESWS for the inspector's
review. The ESWS pumps -(inclucing the ECW pump) have had no
failures within the last two years. The major focus of ESW
maintenance has been the control of crud buildup inside piping
and heat exchangers. This maintenance area was reviewed to
assure that the likelihood of acute episodes of heat exchanger
fouling or major systems leaks is being kept low by arlequate
surveillance and maintenance. The inspector interviewed per-
formance engineers, system engineers, and personnel associated
with ESW pipe replacement and heat exchange cleaning and
-
reviewed related documents. From this review the inspector
learned that during 1984, the ECCS room coolers flow rates had
been decreasing.
Sections of ESW pipe had shown buildup of a hard crud (mainly
iron oxide) on the inside pipe walls. Small pipe leaks devel-
oped, caused by pitting corrosion which did not substantially
affect pipe strength and were easily plugged. Pipes that have
shown localized wall thinning have been replaced (MOD No. 903).
Hydrolyzing of the Torus Room ring header pipes in Units 2 and
3 has been completed as of November 1985 (MOD No. 1557). The
ECCS room coolers have been placed on a program of periodic
flow testing and back flushing. Manual valves have been
installed allowing ECCS room equipment to be isolated for
servicing in Unit 3. The installation of isolation valves in
Unit 2 is planned during the next outage. In late 1985, a
chemical injection system was installed to control corrosion
and crud buildup in the ESW piping.
. .
18
The jacket water heat exchangers servicing the diesel genera-
tors are inspected and cleaned once a year. No major fouling
problems have been observed with these exchangers. Asiatic
clams have been found in the pond water, but growth inside
ESW piping has not as yet been observed. f. program for trend-
ing asiatic clams fouling in oil coolers and heat exchanger
is in place. The inspector observed the back flushing with
both water and compressed air of a thrust bearing oil cooler
of a high pressure service water pump. Periodic backflushing
appears necessary based on the amount of silt observed.
The inspector concluded that continued attention to slit and
crud buildup within coolers and heat exchangers is required,
as is periodic observation of ESW pipe condition. The licen-
see's programs appear adequate to identify and control prob-
lems.
The inspector reviewed the NPRDS data base for all service
water system equipment failures to identify any evidence of
inadequate maintenance or abnormal failure rates. One concern
was raised during this review. On April 17, 1985, gross leaks
were observed in the high pressure service water pump discharge
check valves CV-502 C&D. One month later (5/20/85) CV-502A .
was found hanging open and again a month later (6/26/85)
CV-502B was also found hanging open. This raised a concern
regarding component failure review adequacy. This concern
was discussed with performance engineers. From these discus-
sions, the inspector judged that the System Engineer assigned
to each system does follow system problems very closely and
that he has good maintenance data retention and retrieval
tools at his disposal. Thus, the inspector concluded that
the specific concern dealing with the check valves was an
isolated case. The system engineers were fully knowledgeable
of the specific check valve failures and their causes and
remedies.
The procedures and results of system operability tests, compo-
nents functional tests, and calibrations of system pressure
switches were reviewed for procedural adequacy and correct
implementation. Six surveillance test procedures were reviewed.
The inspector judged that the operability of the pumps and
valves in the system was being adequately tested. When review-
ing the calibration and functional testing of the system
pressure switches, their associated logic and the actuated
relays in the EWS and ECW pump start /stop circuits and MOV-0841
open circuit, two questions were raised.
- _ _ __
. .
19
The first question related to the adequate testing of Agastat
reley #163-1603. This relay automatically starts the standby
ESW pump when the running pump fails. The specific contact
in the starting circuit of the pump is never tested. This
concern was raised with the Systems Engineer. It was deter-
mined that a second contact of the relay provides annunciation
to the control room ESW low pressure a,larm and that this con-
tact is tested to provide assurance that the relay is activated.
The licensee investigated the possibility % bat the contact in
question be tested. It was determined th6 : lead would have
to be lifted in order to test the contact. The inspector was
shown an acceptance test that demonstrated that the contact
was correctly wired and performed its function. The inspector
judged that the use of the annunciator to check the relay was
superior to requiring a lead to be lifted. The test method
was therefore judged adequate.
The second question involved adequate pressure switch calibra-
tion. The Emergency Service Water header low pressure permis-
sive switches, PS-0240 A&B and PS-0246 A&B for valves MOV-0841
and MOV-0498 respectively, were visually inspected. One of
the objectives was to evaluate the configuration of the' switch
locations for instrument calibration, particularly for possible
valve-in and valve-out errors. Calibration procedure ST 2.25.7
was reviewed for technical adequacy, including the necessary
steps to restore the instruments after calibration. Three
calibration records dated June 22, 1984, May 26, 1985, and
December 11, 1986 were evaluated. The review included instru-
ment drifting by comparing the "As Found" and "As Left" cali-
bration data.
Each pressure switch PS-0246 A&B had a high pressure and a low
pressure contact and opening and closing setpoints of each
contact were required to be calibrated. For example, open
and close setpoints for contact #1 and #2 are required to be
calibrated. The purpose was to verify that the contacts would
open again if the header pressure was sufficiently higher than
their setpoints. Contrary to this, the calibration records
of May 26, 1985 and December 11, 1986 indicated that the reset
points were not calibrated. The licensee representative stated
that reset was routinely checked during the calibration but
their reset values were not recorded and that the calibration
procedure would be revised to clarify the calibration require-
ments. This is an unresolved item pending a revision of the
calibration procedures and NRC inspection (277/86-25-05).
3.5.2 Emergency Cooling Water (ECWS)
The ECWS provides the ultimate heat sink in the event of the
loss of river water. Though the ultimate heat sink function
was not identified in any of the dominant accident sequences,
parts of the system are used as backup for the ESW cooling
.. .
20
functions. The inspection focused on the ECW pump and asso-
ciated valves that provide the ESW backup to cool diesel gen- *;
erators and other vital components. The visual inspection,
operability testing, and system simulation concerning the
ECW pump and discharge valve have already been discussed in
the preceding section.
One of the alternate cooling paths evaluated as safety signi-
ficant in NUREG/CR-4550 starts at the ECW pump where cooling
water is directed through the ESW components (diesel coolers
and ECCS pump rooms) passes through the Emergency Service Water
Booster Pumps (ESWBP) and is discharged back to the Emergency
Cooling Tower. This cooling water path is required if the pond
discharge valve is failed closed or if the ultimate heat sink
mode is in operation. The inspector walked down this path and
determined that the as-built configuration agreed with the
P&ID's. The viability of this path'was reviewed for adequate
system flow, i.e., could the ECWP provide sufficient flow
, through stopped booster pumps back to the cooling tower. The
licensee provided a completed ST/ISI-6 test procedure conducted
on June 19, 1985, in which the ECWP was operated in conjunction
with throttled cooling tower inlet valves to provide system
pressure high enough to satisfy an ISI system pressure test.
The flow under these conditions, based on the pump head curve,
showed a flow of at least 4000 gpm. Based on this test, it was
judged by the licensee that adequate ECW cooling flow would be
provided without the assistance of an operating booster pump.
Peach Bottom Units 2 and 3 are provided with an emergency heat
sink for removing heat from the reactor systems so that the
both reactors can be shutdown safely in the unlikely event of
the non-availability of the normal heat sink, the Conowingo
Pond. The ECWS is to provide an adequate on-site heat removal
through the emergency service water pumps and the high pressure
service water pumps and a mechanically induced draft cooling
tower and its on-site emergency water storage reservoir of 3.7
million gallons of water. The heat sink is common to Units 2
and 3. It is designed to withstand a seismic event. A total
of three cooling tower sections with a dedicated fan per each
tower is provided.
The inspector made an independent calculation of heat removal
requirements, three hours after a reactor shutdown, based on
the FSAR heat removal capacity of each cooling tower.
-
1 (one) Fan Heat Removal Capacity:
178.5 x 10' BTU /HR
-
Heat removal requirements, 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after trip
(a) Decay heat, 112 x 10' BTU /HR
(b) One Diesel Generator Heat Load:
Lube 011: 2.75 x 10' BTV/HR
Jacket Water: 3.0 x 10' BTU /HR
Air Cooler: 2.4 x 10' BTU /HR
.
.
. .
21
Since each diesel generator heat load is about 8 million BTU /
HR, one section of the cooling tower easily can support two
diesels (16 x 10' BTU /HR) and decay heat from one reactor
(112 x 10' BTU /HR).
When the ultimate heat sink mode is actuated, four sluice
gates, M0-2233 A&B and M0-3233 A&B, are closed to isolate the
inlet structures from the river. The inspector made visual
inspections and reviewed sluice gate design and surveillance
tests to determine if the gates have closed reliably and were
sufficiently leak tight. The visible components appear in
good condition. Review of operability procedures indicated
that the gates have operated reliability and that the amount
of silting under the gates have been monitored and controlled.
However, no test for sluice gate leakage is conducted and no
underwater examination of a closed gate has been performed.
The gate is of a low leakage design that depends on adjustable
wedges to provide a good seal. The inspector discussed this
concern with performance test engineers. The conduct of
periodic underwater visual examination of the gates in the
closed position to assess their condition and assure they
adequately seal is an unresolved item (277/86-25-06).
3.5.3 Diesel Building and Battery /Switchgear Room Ventilation
The purpose of the diesel generator building ventilation system
is to provide an adequate supply of outside air to each engine
room for personnel occupancy, equipment protection and diesel
engine combustion air. The HVAC system also recirculates
engine room air as necessary to maintain suitable room temp-
erature for equipment protection and to provide supplemental
heating for equipment freeze protection. The battery and
switchgear room fans, including standby fans, maintain suitable
temperatures in the rooms for normal and emergency conditions.
The NRC inspector reviewed the operability of the diesel
generator building fans and the modulating action of the
outside air inlet damper and recirculation air dampers. The
setpoint of a fan discharge duct temperature indicating con-
troller controls the opening and closing of the outside air
dampers. During the performance of the weekly EDG surveillance
test, the NRC inspector did verify that the ventilation fan and
the modulating dampers perform as required. The inspector
could not verify the operation of the supplemental supply
fans since they onerate only when the outside ambient tempera-
ture is above 65 F.
t
b
, ,c --n - -
. .
22
When reviewing the maintenance program for the fans and
dampers, the inspector noted that the licensee has never *
.
documented any maintenance on the ventilation fans OAV 64,
OBV 64, OCV 64 and ODV 64 or dampers and has performed docu-
mented maintenance on only two of the four supplemental supply
fans. No evidence of fan failure was found.
Similarly, no documentation for the maintenance of the cooling
fans OAV-36 and OBV-36 for the battery rooms or the tests for
the control system for louvers and dampers in these rooms could
be found. This also includes standby fans for the battery and
switchgear rooms. In addition, no functional testings of
differential pressure switches DPS-23-1, 23-2, 28-1, and 28-2
was performed. These switches start the standby fans for the
battery and switchgear rooms in the event the normal fans fail.
Also, no evidence of fans or ventilation system failures was
found.
The apparent lack of maintenance on the main and supplemental
diesel room fans and the lack of testing of the supplemental
fans presents a common cause HVAC failure concern and warrants
attention. Fan failure for the battery and switchgear rooms
likewise presents a potential common cause failure concern.
The licensee has agreed to implement an existing preventive
maintenance and testing program on the fans and dampers. This
is an unresolved item pending full implementation of the
maintenance program (277/86-25-07).
No violations were identified.
3.6 Procedures and Operations Dealing With Electrical Power Upsets
3.6.1 Loss of One or More Offsite Power Sources
The inspector reviewed the following procedures: S.8.3.D.1,
S.8.3.D.2, S.8.3.D.3, S.8.3.H, S.8.4.A, S.8.4.F, T-100, T-101;
the full titles and revisions are detailed in Appendix A. He
also observed plant simulations on portions of these proce-
dures. The review of the procedures determined acceptability
and the plant simulations with various operations personnel
(shift superintendent, shift supervisor, control operator and
plant operator) determined the actual workability and perform-
ability of the procedure and any human factor problems.
The licensee has procedures to cover plant responses following
loss of either electrical power startup sources or plant scram
following loss of offsite power.
r
. .
23
When either a scheduled or unscheduled outage of one of the
two offsite startup power sources occurs, the E-2 Diesel i
Generator is started and is aligned to feed the E-22 bus and
the bus is isolated from the offsite startup source. The
inspector reviewed this situation in light of Information
Notice 84-69 " Operation of Emergency Diesel Generators" which
cautions operation in this mode if automatic load sequencing
is affected during an accident situation. The inspector
reviewed PORC Minutes BWR 84-153 and reviewed the electrical
schematics with the systems engineer and determined that this
mode of operation will not affect the automatic load sequenc-
ing during an accident situation.
Following a scram with loss of offsite power, if one diesel
generator is operating, the plant can be maintained in a
stable condition. Therefore, the inspector reviewed the
licensee ability to utilize any diesel generator to cross
connect to a 4 KV bus other than the one it normally feeds.
This is especially important at Peach Bottom since diesel
generator E-1 is dependent on either E-2, E-3 or E-4 to power
emergency service water or emergency cooling water pumps.
Procedure S.8.4.F is utilized to cross connect 4 KV emergency
buses. The inspector simulated the procedure with licensee
operations personnel. During the simulations, the operators
were knowledgeable of the limitations on diesel generator E-1
and the need to assure cooling water was supplied within three
minutes after diesel start. If diesel E-1 were the only
diesel to start following a demand, the operators stated they
would trip the diesel, set-up and then perform the cross
connect procedure. Estimates of thirty minutes to diagnose
the need, set up and perform the procei re were suggested by
operations personnel.
The inspector independently walked through the steps of the
procedure and determined that five minutes would be the minimum
time to physically perform the out of control room steps.
The conclusion of the simulation is that the procedure is
capable of being performed in the environment in which it
would be needed but requires considerably more than three
minutes. The operators are knowledgeable of the plant and
able to implement the procedure. If E-1 is the only diesel
generator to start, the time sequencing requires a trip of
the diesel generator, set up and then performance of the
procedure. While personnel were kncnledgeable of this, the
procedure itself makes no mention of the proper sequences,
showing a problem with the procedure. Additional human factors
findings are discussed in Section 5.1.
_ __ ___-
-
. .
s
24
Simulation of the T-100 and T-101 procedures for the loss of
offsite power and review of actual plant response to an MSIV *
,
closure transient showed that use of High Pressure Coolant
Injection system (HPCI) for pressure control and reactor core
isolation cooling (RCIC) system for level control would ade-
quately maintain stable plant conditions. Operations personnel
were knowledgeable of indications, procedure intent and .
necessary equipment.
No violations were identified.
3.6.2 Station Blackout
l
The inspector reviewed the following procedures: T-100, T-101,
T-102, T-112, E-28, S.8.5.E and S.7.2.M and observed operators
performing plant simulations on portions of these procedures.
The reviews of the procedures determined technical adequacy
and the plant simulations with various operations personnel
(shift superintendent, shift supervisors, shift technical
advisor, control operator, plant operator and assistant plant
operator) determined the actual workability and performability
of the procedures and showed some human factor problems. The
inspector reviewed drawings E-1065, E-1069, E-1071, E-1073,
E-1074 and E-1075 to determine if emergency lighting was
sufficient to perform the required tasks.
During the inspection, the licensee stated that the symptom
based Emergency Operating Procedures are being revised to
incorporate the event based emergency procedure (E-28) f or
station blackout. This is scheduled for completion by August
1987. The inspector utilized the existing E-28 for his review
and plant simulations.
The operators have been instructed to use the station blackout
procedure in parallel with the emergency operating procedures
(EOP) until the procedure is incorporated into the E0P's. The
inspector observed that the activities required in E-28 closely
parallel the E0P's. The E0P's will provide insight as to when
<
a particular activity is required to be accomplished.
Not all the parameters required to be monitored per the E0P's
are currently fed by DC power sources and would therefore not
be available in a blackout condition. Drywell pressure and
r torus level will be available in the siternate shutdown panel
i
being added for later use and are being evaluated for incor-
poration into the control room. When the revised E0P's are
issued, the availability of instrumentation to monitor the
required parameters during a blackout will be identified.
_ _ - _ _
-
. .
25
E-28 utilizes HPCI, RCIC and the relief valves to cool the
reactor and transfer the heat to the suppression pool. While
this is not an indefinite heat sink, this heat sink is adequate
-for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> following a plant scram. The source of
control power for HPCI and RCIC as well as some of the plant
lights is the 250V DC supply. The procedure contains steps
to maximize the availability of the DC supply. Whereas pre-
vious analysis has assumed the design of the DC power supply
is 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, the procedure attempts to extend battery avail-
ability by eliminating unnecessary DC loads. The exact length
of time available is not currently known, but the licensee is
planning to determine this. One reason for not knowing the
time duration of the battery supply is related to the lack
of precise knowledge of the battery loads as identified as
an unresolved item in Section 3.4
The inspector's conclusion from the plant simulations is that
the plant staff is very knowledgeable of the plant and is
readily able to implement these procedures. The procedures
are basically workable, however some observations regarding
human factors and performance are discussed below:
The E-28 procedure required that steps be performed on the
HPCI turbine itself to result in the control valves failing
open on loss of DC power. The inspector questioned the proper
timing of this step since it requires entry into the HPCI room
when the turbine is running and it will take two people away
from other tasks that may be more important, such as starting
up diesels. It also required tripping of 'he HPCI turbine when
the feed flow may be required. Better c , aria for deciding
when this operation is required are needed.
The inspector reviewed HPCI and RCIC room temperature profiles
when no forced cooling is provided, as would be the case during
a blackout. The inspector concluded from these results that
room temperatures can affect the ability to operate for long
periods. Temperatures can be moderated somewhat by providing
additional circulation by opening of the room doors to the
corridor. The licensee agreed to incorporate this provision
into the revised procedures.
The licensee informed the inspector that a modification of
approach to the blackout procedure is being evaluated regard-
ing whether the HPCI/RCIC suction should be transferred from
the condensate storage tank (CST) to the torus early in the
event. If this is not the case, then the procedure requires
additional steps to preclude automatic transfer on high torus
levels and also requires that CST reflood capability be
defined. The inspector simulation of S.7.2.M deconstrated
, , - - - - - . . . - _
. _ _ _ - _ _ - _
. .
26
one method of adding more water to the CST. In addition the
licensee is developing plans to use the diesel fire pump to *i
refill the CST. The inspector observed the potential connec-
tion location and determined that it is in an accessible
location. This will be incorporated in the future revision
of the E0P's. Additional human factors observations are
contained in Se: tion 5.1.
The revisions required to incorporate the station blackout
procedure into the E0P's along with other procedural changes
discussed in Sections 4.3.3 will be an unresolved item.
(277/86-25-08).
3.6.3 Power Restoration l
The ability to restore the electrical power to the plant was
,
!
assessed. Several means of communications are available and
the Philadelphia Electric Company has a procedure for restoring
the electrical grid should the system suffer a complete shut-
l down. This procedure utilizes the Conowingo Dam generators
to energize the system. Peach Bottom procedure S.8.3.M would
be used in conjunction with the system procedure to restore
offsite power. The inspector had no questions regarding power
restoration.
4.0 ACCIDENT SEQUENCES INVOLVING TRANSIENTS WITH CHALLENGES TO CONTAINMENT
The sequences leading to the equipment and procedure examinations discussed
in this section have as common initiators the family of events known as
Anticipated Transient Without Scram (ATWS). The power plant does not have
sufficient energy removal capability in these events so that a high pressure
.
in containment results. One way to preserve containment integrity is to
deliberately vent the gases in containment to the atmosphere to reduce the
pressure in the containment vessel; when and under what conditions this
should be done is a matter of controversy. How containment venting can be
accomplished at Peach Bottom and the procedures by which it can be done were
inspected; the result is discussed here. Some of the equipment involved in
ATWS event sequences - safety / relief (SRV) and main steam isolation valves
(MSIV) and SRV's used in the Automatic Depressurization System (ADS) -
is discussed in this section. Availability of High Pressure Coolant Injection
(HrCI) is discussed in Section 5.3. Procedures and equipment utilized for
containment venting are reviewed in Section 4.3. Operator response and
procedures to cope with ATWS are discussed in final part of this section.
4.1. Sequences, Failures and System Considerations Including ATWS
The sequence resulting in failure from ATWS involves as initiating events
turbine trips, MSIV closure, loss of feedwater, open relief valve or loss
of offsite power. After the initiating event, the reactor fails to scram
(control rods fail to insert). The operators respond by attempting to
insert control rods and reduce power by a variety of methods. Reactor
coolant inventory is maintained by feedwater, HPCI and or RCIC injection.
.
_ _ _ _ - _ _ .
. .
27
If the MSIV's are closed the only heat sink available is the suppression
pool. Its finite heat capacity results in failure after a time. In this g
inspection, only portions of the equipment involved in the sequence were
examined. This equipment included such important valves as SRV's and
MSIV's, including ADS operation of the SRV's and those containment isola-
tion valves which would be used to vent containment. Procedures reviewed
and simulated included the containment vent procedures and those portions
of the emergency operating (TRIP) procedures dealing with ATWS. The
results are discussed in sections which follow.
4.2 Main Steam Isolation and Safety / Relief Valves
The inspector conducted a review of procedures and documentation and held
discussions with responsible licensee personnel to identify failures and
problems associated with Main Steam Isolation Valves (MSIVs) and Safety
Relief Valves (SRVs) including the Automatic Depressurization System
(ADS). Although several problems were identified, which will be dis-
cussed below, the inspector considered the components / systems to have a
high reliability and the licensee's actions to identify the root cause
of problems and initiate corrective action to prevent recurrence to be
adequate in most cases.
4.2.1 Safety Relief Valves (SRV) and Automatic Depressurization
System (ADS)
The safety objective of the nuclear system pressure relief
system is to prevent overpressurization of the nuclear system,
protecting the process barrier from failure and resulting
uncontrolled release of fission products. In addition, the
automatic depressurization feature is needed to allow low
pressure emergency core cooling systems to reflood the core
following small breaks in the pressure boundary. This protects
the reactor fuel cladding from failure due to overheating.
The review of data, procedures, and SRV/ ADS machinery history
records for both units indicated past performance for these
components was similar to that of other BWRs. The normal
problems identified included: SRV's opening at power and
sticking open, thus requiring a unit shutdown fcr repairs;
ADS nitrogen / air system leaks; SRV bellows leakage; and ADS
coil shorts. It was evident that the licensee has taken steps
to improve the reliability of the valves through their SRV
performance improvement program. During each refueling outage
at least one safety valve and five relief valves are removed
and sent to Wyle Laboratories for complete refurbishment and
testing. In addition, the licensee installed acoustical moni-
toring devices on the valves to detect internal leakage in the
pilot. Therefore, SRV problems are detected early and normal
shutdowns are initiated to repair the valve prior to sticking
open at power. Since the implementation of the improvement
program in 1980, there has been only one failure; this shows
the actions taken by the licensee have had a positive impact
on reliability.
. . ._. .. . -
. .
28
Review of ST 13.39 (Main Steam Safety / Relief Valve Challenges),
the licensee's record of any opening of the SRVs in response *i
to a high reactor system pressure condition which occurred
during the previous year as required by TMI action Plan Item
II.K.3.3, ascertained there have been no challenges since 1981.
Review of the CHAMPS data, which provides the maintenance
history of plant components / systems from late 1983 to the
present, shcwed that only 'ninor corrective maintenance has
been required.
Discussions with the system performance engineer and the
Instrumentation and Controls (I&C) supervisor indicated the
surveillance testing of the system (logic, functional,
instrumentation calibration, and leakage tests) showed the
system to be reliable with only minor problems.
The I&C supervisor informed the inspector of the licensee's
new ST Tracking System implemented earlier in 1986. Using
this system, I&C personnel document the status of each sur-
veillance test performed on the various instruments through-
out the plant. The "as-found" condition (sat or unsat) and
the direction the instrument was found to be out of calibration
(high or low) is recorded and tracked so that a potential
instrument problem is readily identified and reported to the
I&C Engineer, who determines the corrective actions to be
taken. The inspector reviewed the data for ADS system initia-
tion instrumentation documented in this system and found it to
be highly reliable. The inspector conducted a walkdown of the
backup nitrogen supply system which includes nitrogen bottles
in the reactor building already connected and available for
service and a remote connection station outside the reactor
building which requires the connection to be made up to a
nitrogen supply (bottles, truck, etc.). The inspector con-
sidered the nitrogen supply to the ADS valves to be very
reliable as the accumulators are sized to provide enough
nitrogen pressure for a minimum of five actuations with normal
make up coming from the instrument nitrogen system. In the
event the normal instrument nitrogen supply fails, a back up
system of nitrogen bottles is readily available in the Reactor
Building, further backed by the ability to provide any amount
of nitrogen required at the remote connection outside the
Reactor Building.
One concern identified in this area of the inspection dealt
with the "as-found" setpoint of the SRVs. ASME Code,
Section XI, IWV-3510, requires that the "as-found" setpoint
of the SRVs be determined, since any valve that failed to
function properly during a regular test would require addi-
tional valves to be tested per IWV-3513. Review of the
licensee's procedures and documentation for replacement of
- . _- - __ - _-_ ___-___
. -.
29 .
the SRVs, ST 13.32 and M 1.6, indicated that the "as-found"
setpoints are not addressed. ST 13.32 only requires that the i
"as installed setpoint of the removed valve" and the "setpoint
of the installed valve" be documented. In addition, Wyle
Laboratories Certification Test Report attached to ST 13.32
indicated the valve was refurbished prior to testing and only
the "as-left" test results were included. When responsible
licensee engineers were questioned concerning this issue, they
stated they were not aware of the requirement to perform
"as-found" testing. In a subsequent discussion with QC
personnel, they stated the "as-found" testing was performed
by Wyle and the results were attached to the Purchase Order
(P0) that contracted the testing by Wyle. They stated they
were aware the "as-found" testing was performed because that
was one of the items they verified to ensure all the require-
ments of the P0 were met. However, QC was not aware of the
reason for the "as-found" testing nor the action required if
testing found the valves out of tolerance. QC was unable to
determine at the time of inspection if any valves tested pre-
viously failed the "as-found" testing. They stated they would
have to research the previous P0's and contact Wyle to make
this determination. The lack of documentation of as-found SRV
setpoints is Unresolved Item (277/86-25-09) and represents
an example of weakness in technical documentation.
,
4.2.2 Main Steam Isolation Valves (MSIV)
The safety objective of the MSIV's, one on each side of the
primary containment barrier in each of the main steam lines,
is to close automatically to:
Prevent damage to the fuel barrier by limiting the loss
of reactor coolant in case of a major leak from the steam
piping outside the primary containment.
Limit release of radioactive materials by closing the
nuclear system process barrier in case of gross release
of radioactive materials from the reactor fuel to the
reactor cooling water and steam.
Limit release of radioactive materials by closing the
primary contain~ ment barrier in case of a major leak from
the nuclear system inside the primary containment.
The review of applicable documentation (see Appendix A) indi-
cated the performance history for the MSIV's was similar to
that of the SRV's discussed earlier. The recurring probler.is
identified included: failure of local leak rate testing due
to seat leakage, solenoid coil failure and limit switch
failures.
.
_
. .
30
Discussions with site performance engineers and corporate
engineers revealed an MSIV leakage improvement program similar *
i
to that for the SRV's. In addition to their improvement pro-
gram, PECo belongs to the BWR Owners Group (BWROG) tasked with
improving MSIV performance. Corporate engineers stated that
the BWROG recommendation to install anti-rotation devices was
still under evaluation. Review of the past data for MSIV
leakage showed the program, which was started in about 1980,
has had a dramatic effect in reducing MSIV leakage. During
the outages of 1978 and 1980 for Unit 2, all eight MSIV's
failed their local leak rate test (LLRT). Similarly, all eight
Unit 3 valves failed during the 1979 outage. The data shows a
, definite downward trend from the failures in 1978 through 1980
to a LLRT failure of one valve for Unit 2 during the 1984
outage and a failure of 2 valves for Unit 3 in 1985. Review of
NPRDS data showed a high failure rate for the DC coils on the
MSIV solenoid valves (13 failures). Loss of the DC coil
decreases the reliability of the MSIV's to remain open, as only
the AC coil is keeping the valve open. Loss of the AC coil
through testing, loss of power, or coil failure would then
cause inadvertent MSIV closure. Corporate engineering person-
nel stated the DC coil failures were due to aging. At present,
the licensee is replacing all DC coils each outage regardless
of their condition until a permanent solution to the problem
is identified. Similar coil problems have been identified by
other licensees (see IE Information Notice 86-57). Another
possible cause for coil failure is discussed in Section 3.4.
The licensee also developed a new surveillance test (ST 21.9)
to determine if the AC or DC coil has failed. The ST is per-
<
formed monthly and had aided in preventing inadvertent MSIV
closure.
The licensee has instituted the same ST tracking system for
the MSIV's discussed earlier for the SRV's. Review of the
data for the instrumentation associated with the MSIV closure
initiators (Hi Radiation, Hi Flow, Low Level, Low Pressure,
Hi Temp) showed the instrumentation to be very reliable.
4.2.3 Additional Concerns Regarding Valves
Although not directly related to this PRA inspection, the
inspector identified several concerns in the areas of valve
stroke time testing, short stroking motor operated valves
(MOV's), and electrically backseating M0V's.
(1) Stroke Time Testing MOV's
Through discussions with responsible licensee engineers,
the inspector learned that the licensee tests the stroke
time of MOV's from " light to light" indication in the
control room. This method of stroke time testing only
times the valve stroke time between the upper (open) and
_ _. _ _ _ _
._ _ _
f
.. .
31
lower (close) limit switch and not the actual time requir-
ed to fully stroke the valve. ASME Code,Section XI, *
6
IWV-3413, requires that power operated valves be timed
from the initiation of the actuating signal to the end of
the actuation cycle (contact to contact time). The limit
switch trip points are not normally the initiation of the
actuating signal nor the end of the actuation cycle on
the majority of power operated valves. Thus, the method
used for stroke time testing does not give the complete
stroke time of the valve.
For a valve closing, it eliminates the times required for
the actuation signal to reach the motor; motor spinup time
to cause the hammer blow effect; the time from the hammer-
blow until the first limit switch is tripped, and the time
from when the second limit switch is tripped until the
torque switch trips power to the motor, the end of the
actuation cycle. Therefore, the time would be less than
the time determined by code requiements.
Further, the method may mask a problem with the MOV, since
only the time between upper and lower limit switches is
being measured. Thus, the valve disc / wedge is already
moving when the time is started. This is not in accord
with the purpose of trending stroke times for valves to
detect problems.
Discussions with the ISI coordinator and a review of
documentation associated with stroke timing showed that
the licensee was aware of this problem and some licensee
staff members shared the concerns of the inspector.
A review of preliminary data acquired by the licensee
for MOV's in the Core Spray System showed the time differ-
ences to be as large as 5.7 seconds for the two different
methods. For example, M0-5C required 11 seconds to close
using the " light to light" method and 16.7 seconds using
the " contact to contact" method. This apparently inappro-
priate method of valve stroke timing is an unresolved item
(277/86-25-10).
(2) "Short Stroking" MOV's
Discussions with responsible licensee engineers indicated
certain MOV's in the plant were "short stroked" to meet
Technical Specifications time requirements. "Short strok-
ing" means to shorten the actual stroke length of the
valve by adjustment of the limit switches, normally the ,
upper limit switch. The switch is adjusted to trip power 1
to the motor while the valve is a+. some intermediate 1
position and therefore, the valve does not have as far to
travel thus meeting its required closing time.
i
l
i
- , . - - - - . - . -
- - .- . ~. --- . , . -
. .
32
Several valves (M0-74, M0-77, M0-13-15, and MO-13-16)
were identified by the licensee in a memorandum from g
R. S. Fleischmann to W. M. Alden, dated February 27,
1985, as having a stroke length that was too long to
meet the Technical Specification time requirements.
These are 3-inch valves with a valve speed of 12 inches
per minute and a Technical Specification operating time
of 15 seconds. The actual stroke length of the valves j
is 3 and 3/16 inches which leads to a full stroke time
of 15.9 seconds. The memorandum goes on to request a
, Technical Specification change be initiated to increase
the maximum stroke time to 20-25 seconds. The Technical
Specification change had not been generated at the time
of this inspection.
Further discussions with licensee personnel indicated that
additional MOV's may be "short stroked" in order to meet
required operating times, either Tech Spec or ISI times. This
was identified during discussions with electrical department
personnel who adjust the limit switches after maintenance on
the MOV's. The adjustment procedure, Maintenance Procedure
M-9.1, requires that the apper limit switch be adjusted such <
that the valve motor will trip prior to the valve disc / wedge
reaching the backseat, taking into account the effects of
inertia. The electricians stated that when making this adjust-
ment they also review the timing requirements of the particular
valve and adjust the limit switch, if required, to meet the
time. Thus, when the stroke time retest required after main-
tenance was performed the valve would pass because the limit
switch was already set up to ensure this. The inspector also
reviewed several Maintenance Request Forms (8501591, 8508084,
and 85030239) for M0V's (M0-2-12-68, M0-3-12-68, and M0-02-074
.
respectively) in which the problem description indicated the
i
valve stroke time was too long. The corrective action required
the limit switch be adjusted to meet the proper stroke time.
The areas of concern in this issue are:
(a) "Short Stroking" of valves, without strict engineering
control, could result in the valve disc / wedge partially
inserted in the flow path and thus reducing system flow.
(b) "Short Stroking" may also mask a valve problem that would
normally be identified as increasing stroke time.
,
The licensee indicated that Maintenance Procedure M-9.1 was
currently being revised and the inspector was provided with
a draft copy. Review of the draft copy showed the procedure
required that valves be set a specified distance from the
backseat (either in number of handwheel turns or inches) and
would remove the inspector's concern. Additional followup
will occur during routine inspection program.
.
.
__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _
.. ..:
33
,
(3) Electrical Backseating of MOV's
The practice of electrical backseating is'used on M0V's inside
the drywell suspected of having excessive packing leakage.
In this method of backseating a M0V, an operator manually.
closed the motor contacts at the motor control center (MCC)
to energize the MOV motor in the open direction. This causes
the MOV to open past the open limit switch and then continue
to open until the stem drives into the backseat of the valve
bonnet. The operator uses a clamp on. amp meter installed on
the wires'at the MCC going to the motor. When he notices an
increase in current draw on the amp meter, he then releases
the contacts previously held closed. The increase in amperage
indicates the valve stem has contacted the backseat and the
. motor is at or near locked rotor current. Although the valve
has:a backseat provided for the specific purpose of limiting
excessive packing leakage, it is designed to be backseated.
manually without using excessive force. The practice of
electrically backseating MOV's leads to the following problems:
(a) Excessive force is_ applied to the stem, bonnet backseat
area, actuator gearing and internals, motor, motor pinion
gears and key. There are numerous cases of MOV failure
due to excessive force whether from backseating, improper
limit switch adjustment, or some other cause. Damage has
included:- total stem shear, motor failure, motor pinion
gear and/or key failure, and actuator gear /or bushings
failure.
(b) Backseating valves is typically not done under procedural
or technical control.
(c) Valves that have been backseated are not inspected after
the act for damage that may be caused by excessive forces.
The licensee is aware of the problems associated with elec-
trical backseating and has been since at least 1982 when the
issue was addressed in a memorandum from W. T. Ullrich to
G. N. DeCowsky, dated March 1,1982. Discussions with licensee
corporate engineering personnel indicate they are presently
working on the issue of backseating and a means to eliminate
need to backseat.due to packing leakage. They stated they
were presently working on Mod Package 1909 which would elimi-
nate packing leakage by modifying the packing gland area,
replacing the existing asbestos based packing with graphite
packing, installing carbon bushings, and live loading the
packing to allow slight movement during temperature changes.
,
. .
34
In addition, Mod package 1028 was in the process of being
implemented to address the issue of backseating valves. This
Mod would require vendor and/or consultant analysis to deter-
mine the ability of the valve to withstand backseating forces
and to develop a means to reduce the impact on the valve during
backseating.
4.3 Containment Venting - Emergency Procedure
Effective containment venting for elevated containment pressure is a
means to mitigate an overpressure challenge to containment integrity in
severe accidents. Successful containment venting under severe accident
conditions reduces the likelihood of containment failure and the sub-
sequent uncontrolled release of radionuclides. The objective of this
part of the inspection was to assure that containment venting could be
achieved effectively and realistically if needed.
To attain this inspection objective, control room and local equipment
operations were evaluated by walkdown simulations and procedural reviews
for adequacy. Various containment venting pathways were evaluated for
availability and practicability of venting operations.
4.3.1 Event Initiation and Pressure Control
The Peach Bottom station uses both symptom-oriented (TRIP) and
event-oriented emergency procedures, depending upon the
sequences and nature of the emergency event. The emergency
blackout procedure E-28 is an event-oriented emergency proce-
dure discussed in Section 3.6.2. The containment venting
procedures are system procedures and deal with specific
operational steps to perform emergency containment ventings
via available pathways.
The inspector conducted a simulation of control room operations
with a reactor operator (RO) who has 6 years of experience as
control room operator and a total of 16 years with the plant.
The inspector discussed control room indications, alarms, and
various system operating procedures and observed anticipatory
reactions and operational steps leading to the containment
pressure controls and the TRIP procedure. The simulation was
also discussed with a Senior Reactor Operator (SRO).
The control room R0 demonstrated response and recovery actions
based on the simulated ECCS actuation indications as would have
been displayed on the control room indicators. Alternative
actions, including local operations, were simulated if the
automatic features failed to respond. Specific control room
parameters (i.e., level, power, or pressure) and conditions
leading to the reactor scram and the TRIP procedures were
-
, ..
- .. ..
35
discussed. The'R0 also simulated and discussed alternate
control room operations when the automatic features and front *;
panel manual actions for reactor scram failed. He obtained a
key for individual control rod scram cabinet from the shift
superintendent's desk drawer and simulated individual control
rod scrams. He also stated that if the individual scram
cabinet key could not be located in a timely manner, the
operator would break the cabinet's plexiglass door.
The procedures discussed or partially simulated include
S.3.2.B.1, S.3.2.B.3, OT-101, and S.3.10.b. The inspector
observed that the TRIP flow charts were available and located
in the control room for easy access and use: other emergency,
TRIP and system operating procedures were also in the control
room. Based on the above observations, the inspector deter-
mined that the control room operators were knowledgeable and
capable of. recognizing, responding and performing normal or
alternate control room operations.
If the event or abnormal plant conditions propagate beyond the
normal responses, the operators were capable of using the
appropriate emergency procedures.
4.3.2 Containment Pressure Controls
Containment venting is a means to manage accident sequences
involving the loss of heat removal capability. The inspector
conducted simulated emergency operations with control room
SRO and RO for accident sequences leading to containment
venting.
Under a LOCA or loss of long term cooling, the operator effect-
ively demonstrated appropriate mitigation operations using TRIP-
procedure T-102, " Containment Control". The operator simulated
torus spray operations employing S.3.2.V.3 and containment
blowdown pressure control operations per procedures T-112 and
T-116. The inspector noted that TRIP procedure T-102 does not
call for containment venting procedures until containment
pressure reaches 100 psig. No other provisions or decistor,
guides were included in the TRIP procedure when the containment
pressure is rapidly increasing or when pressure suppression
systems failed to control the containment pressure buildup.
The 100 psig is a generic threshold point to initiate contain-
ment venting regardless of accident sequences or event progres-
sions.
A station blackout with core degradation sequence was simulated
using emergency procedure E-28. Even though the control opera-
tors clearly understood the need to use both E-28 or T-102
procedures concurrently when the drywell pressure exceeded
2 psig, no clear guidance was provided in either E-28 or T-102
_, _ _ _ _ . . _ _ _ . _ _ _ _ _ _ . - _ . . . . . - _.__ .___.-
. .-
36
under blackout situations. In fact, most of the intermediate
steps given in the drywell pressure control branch of T-102
would be precluded under this accident sequence since electric
power would not be available. According to a recent study of
containment venting analysis by NRC (Draft NUREG/CR-4696) the
decision making process and subsequent timing of containment:
venting could be an important factor in successful venting.
In a plant-specific analysis, the integrated containment analy-
sis report of Peach Bottom station by Industry Degraded Core
Rulemaking (IDCOR) program, March 1985, the reactor vessel is
predicted to fail 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after onset of the blackout sequence
followed by predicted containment failure in 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. Once
the station battery runs out in about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (assuming no
conservation measures) following the station blackout, the
reactor vessel is predicted to fail and the containment pres-
sure would then increase stepwise from approximately 30 psig
to 90 psig, pointing out the difficulty of maintaining con-
tainment integrity, under the T-102 100 psig venting initia-
tion criteria. The licensee stated that the 100 psig venting
criterion of T-102 was being revised; a value of 60 psig was
under consideration.
The ATWS event was simulated with a SRO using T-101 and T-102,
and a simulation of emergency blowdown per T-112 was demon-
strated. The inspector again determined that the operations
staff were knowledgeable and familiar with the control room
emergency and abnormal indications, operations, and recovery
actions.
These observations were noted during the course of the
simulations:
The containment venting criteria (100 psig) of TRIP
procedure T-102 appears to be impractical; procedures
should contain provisions, guidance and/or criteria for
different accident sequences, including the blackout
event.
- E-28 did not include specific instruction to defer to
T-102 as an anticipatory step, which may ultimately lead
to containment venting.
Prior to containment venting, several steps, including
the use of jumper wires to bypass the containment isola-
tion actuation signal, should be taken early enough to
vent the containment in a timely and successful manner.
__ .
.
1
. .
l
37
l
l
4.3.3 Containment Venting System
'
i
The containment venting system consists of several pathways
that were originaly designed for other purposes. A total of
eleven venting paths are available for containment venting.
Three different kinds of paths are discussed here.
(1) Two venting paths, one each on the drywell and wetwell,
are normally used to exhaust gases from the containment
,
I
to the Standby Gas Treatment System (SGTS). Each line
includes a short run of 18" steel pipe and two air-
operated butterfly valves in series. The wetwell valves
are located on top of the torus and the drywell isolation
l valves are located in the reactor building at the 195'
l
elevation. Downstream of the outboard valves are sheet
metal ducts, normally used for typical heating and venti-
lation system. A visual inspection identified several
holes on the discharge duct from the outboard isolation
valve. Similar 18" valves on each of two venting paths
at the supply side of the SGTS are used.
(2) Other venting paths consist of two 2" lines, normally used
to bleed nitrogen from the containment to the SGTS, that
are available from both wet and dry wells. Two isolation
valves on each path are required to open to successfully
vent.
(3) A third available venting path involves a 6" containment
pressurization line normally used for the integrated leak
rate tests (ILRT). There are also two venting paths from
the drywell floor and drain sumps to the radioactive
liquid waste collecting tank.
The inspector reviewed containment venting procedures listed
in Appendix A. Portions of the procedure execution were simu-
lated with an APO or P0 and control room operators. The simu-
lations included applications of jumper wires to bypass the
containment isolation signals for the venting valves, control
room operations of 18" butterfly valves, and manual operations
using pressure regulators and service air or backup gas at the
195' elevation in the reactor building. Emergency situations,
both radiological and steam environment, were simulated and
discussed with the P0 during various postulated events.
Observations resulting from this review and simulation were:
The TRIP procedure T-102, containment venting step,
DW/P-22 specified three venting procedures; S17.3.A,
T-200, and T-201. However, priority of the eleven con-
tainment venting paths was not clearly presented, even
though some pathways were discussed in each procedure.
The need to consolidate and logically order the several
venting procedures was acknowledged by the licensee.
r
I : .
L
38
For vent valves, several leads have to be lifted to by-
pass the isolation actuation signal and thus operate the
, valves. The licensee now has a special tool box in the
!
'
centrol room for this purpose. However, procedure T-200
and other venting procedures require lifting leads when-
ever the valve is needed to operate. This piecemeal lift-
ing of leads complicates the procedural steps. Anticipa-
tory actions lifting all or groups of the required leads
in procedure T-102 could improve the emergency response.
Procedural steps 6 and 8 in T-200 require a cap or plug
to use a pressure regulator for manual operation of the
air-operated 18" butterfly valves. However, the proce-
dure did not specify the plug type or size. A laboratory
technician, with over 18 years of plant experience, pre-
pared the correct parts based on his experience. Speci-
fication in the procedure would reduce error or delay.
I
l
- Even though emergency portable air bottles were available l
for local emergency operation of air-operated valve, this
was not specified in the containment venting procedures.
'
Radiological and physical / environmental protection
required for the local valve operator was not included
in any of the venting procedures.
The inspector raised a concern regarding the high pressure
gradient across the containment venting valves in emer-
gency operations. For example, T-102 specifies opening
A0V-2507, an 18" butterfly valve, using the portable
pressure regulator or remotely from the control room.
6 The specified condition for opening these valves would
involve a pressure gradient in excess of 100 psi. In
fact, all eighteen purge and vent valves were modified
on February,1986 to increase the angle of opening from
, 37 to 70 -50 in order to reduce the containment inerting
and deinerting time from 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> to 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />. The inspec-
tor observed that this modification also would decrease
the maximum permissible pressure gradient across the
valve. The licensee's internal, hand written memorandum
was provided to the inspector, which indicated that the
valve actuator for an 18" valve could open the valve to
an angle less than 40 at a pressure gradient of 130 psid
across the valve. However, the calculation sheet evaluat-
ing the valve performance and pressure differential
did not deal with local valve operations.
The licensee stated that the 18" drywell vent valves,
A0V-2506 and -2507, were previously used to vent the
50 psig containment pressure at the conclusion of the
ILRT.
_ _ - _ _ - - _ _ _ _ _ _ _
. .
39
Licensee representatives agreed that the TRIP, E-28, and system
venting procedures need improvements, and the above findings l
would be incorporated into the revisions. They further stated
that the several containment venting procedures would be con-
solidated and venting paths would be prioritized depending on
the nature and sequence of the events. These findings, along-
with others discussed in Sections 3.6.2 and 4.4., are identi-
fied as planned procedural changes and collectively constitute
an unresolved item (277/86-25-08).
4.4 Anticipated Transient Without Scram
The inspector reviewed the following procedures: T-100, T-101, T-102,
T-112, R-117, T-111, T-210, T-211, T-212, T-220, T-224 and performed
plant simulations on portions of.these procedures. The procedure reviews
determined technical adequacy and the plant simulations with various
operators (shift supervisors, shift technical advisor and plant opera-
tors) determined the actual workability and performability of the proce-
dure and any human factors problems.
The ATWS procedure requires time critical steps such as initiation of
standby liquid control and inhibition of automatic depressurization
when purposely lowering reactor level. During the simulations, the
operators were aware of the time critical steps and were knowledgeable
in their performance.
During the simulation of scramming a rod individually at the hydraulic
control unit by directing the effluent line to radwaste, some time was
required to find the necessary tools to perform the activity. The
licensee activities regarding special tools is discussed in Section 5.1.
Other human factors consideration are also discussed in Section 5.1.
5.0 INSPECTION OBSERVATIONS REGARDING pRA
5.1 Human Factors Engineering
The following observations were made during the inspection walkdown
tours:
5.1.1 Equipment / Facility Identification
The inspector observed that control alarms were grouped
together, and color-coded triangular tapes were attached on
the alarm windows to provide guidance and quick responses for
the control room operation. As discussed in Sections 3.3 and
6.2, the Critical Equipment Monitoring System (CEMS) was
partially implemented. When a valve configuration is changed,
the CEMS-coded valve status information could be entered into
the system manually; this is a prelude to using bar-code
readers and status tracking computer programs.
. .
40
-
5.1.2 Access to Keys
During a walkdown exercise of containment venting, the inspec-
tor simulated a loss of security door control power and
requested security personnel to open the vital access door
leading to the reactor building from the turbine building at
165" elevation. It took more than 8 minutes to dispatch
security personnel.
5.1.3 E0P Simulations
During the simulations of procedures, several human factors
considerations were identified and are summarized below.
During the simulation of the procedure for cross connecting
the diesel generators, it was observed that due to the space
and height of the 127X relay off the ground, the label could
not be read. In addition, some sort of ladder is needed to
reach the relay. The' access problem and additional labels
should be provided to assure this activity can be performed
during the stressful time that this procedure would be needed.
During the ATWS simulation the inspector observed that in
procedure T-101, steps RC/Q-40 and RC/Q-43 refer to the same
valve; however, the valve is called by two different names in
the steps. This lead to confusion on the operator's part as
to what valve was to be operated. This is another example of
inconsistent labelling which is included as part of open item
(277/86-25-01).
During several simulations, additional tools or equipment are
required to perform steps, such as jumpers or wrenches. Opera-
tors eventually were able to find the tools required, but
some time was lost during the ATWS simulation for operations
at the hydraulic control units, for example. The licensee is
preparing controlled packages of special parts needed to
perform steps as required by the E0P's, and marked for each
procedure. This is an ongoing activity and is expected to be
completed with the revision of the E0P's as described elsewhere
in this report. The parts will be stored in a special control
room tool box.
5.2 Reliability and Availability
4
During the course of the inspection, questions dealing with the basic
assumptions of the PRA (NUREG/CR-4550) were raised; discussion of the
questions are summarized below to provide information for the PRA l
developers ,
i
I
. .
41
5.2.1 Frequency of Offsite Power Loss
The frequency of total loss of offsite power of 0.07 per year l
used in the PRA was primarily based on a conservative analysis
of the experience at Peach Bottom to date (13 operating years,
no complete loss of offsite power). The team judged that this
frequency may be high because of the number of offsite power
lines that feed into the two 500 KV st.bstations, the tie lines
to the 220 KV grid, and tt.e availability of nearby hydroelectric
power as well as the redundant tie lines between the substa-
tions that add reliability. The inspector reviewed offsite
recovery plans that give priority attention to returning off-
site power to Peach Bottom from nearby generating stations.
This preplanning increases the likelihood of regaining offsite
power if a total loss were to occur.
5.2.2 Maintenance Outages
PECO has instituted a Safety System Availability Monitoring
Program (SSAMP) that tracks the length of time a safety system
train is out of service during periods where its safety func-
tion is required. A review of 1986 data suggests that diesel
down times are higher than the PRA assumed. The PRA used a
1% maintenance outage time, this is contrasted with an average
down time for the diesels in 1986 of 3.2%. The diesels are
required to be available 365 days of the year because they
service both units; the units are seldom shut down at the same
time so that all maintenance down time counts against avail-
ability. Also, the five day annual outage of the diesels makes
it difficult to achieve an average availability greater than
98%. The licensee is well aware of the importance of minimiz-
ing outage times. All maintenance procedures conducted during
1986 were necessary and were carried out efficiently. When
down, maintenance is conducted continuously on a three shift
basis.
The availability data for the HPCI system was also reviewed.
The average down time for the HPCI of both Unit 2 and Unit 3
was 1.5%; this agrees closely with the 1.6% used in the PRA.
The estab.ishment of the SSAM Program provides a valuable
performance indicator for use by station management to monitor
system availability, reliability and maintenance.
5.2.3 Success criteria
The current draft of NUREG/CR-4550 assumes that one operating
booster pump would be required to use the ECW pump in the
cooling tower mode. During the course if the inspection, it
was determined that the operation of the ECW pump alone with
flow through the stopped booster pumps would provide sufficient
cooling flow. This changes the success criteria of ESW which
. -
42
in turn changes the diesel success criteria, i.e., operation
of either the E-2, E-3, or E-4 diesel assures ESW success and
thus continued diesel jacket water cooling. This determination
should result in more reliable AC/EDG system estimates and
changes in the dominant cut-sets of the PRA.
5.2.4 ESW Limiting Conditions for Operations (LCO)
The Technical Specifications allow the two ESW pumps to be out
of service for 30 days. Considering the importance of these
pumps, especially the support role they play for the emergency
diesels, the LCO appears too liberal. The licensee's PRA staff
has also identified the LC0 as needing review. The inspector
determined by review of the CHAMPS data for the last two years
and interviews with maintenance personnel that two ESW pumps
have never been out of service at one time; thus, it appears
that the LC0 has never been entered. The adequacy of the LCO
in light of the PRA findings requires review. The NRR staff
has been advised of this concern and will be formally requested
to review advisability of a technical specification change.
6.0 ADMINISTRATIVE CONTROLS
The NRC staff reviewed, on a sampling basis, the administrative control proce-
dures listed in Appendix A, and observed the implementation of the station
administrative control procedures to ascertain that the requirements of
Section 6 of Technical Specifications, ANSI N18.7, Appendix A of Regulatory
Guide 1.33, and licensee commitments were met.
Station administrative control procedure A-30, " Plant Housekeeping Controls",
delineated the housekeeping and cleanliness control practices, including
periodic inspection requirements. During routine inspection tours of various
plant areas, the inspectors observed that housekeeping and cleanliness were
in general satisfactory. In fact, physical plant was maintained in an excell-
.
ent state. 13 KV switchgear rooms were not maintained as well as switchgear
rooms in the power block. The high availability of the hardware and opera-
tional awareness of the plant staff are indicators of good understanding of
administrative controls. A problem with operability and location of friskers
was noted early in the inspection, but was promptly corrected.
6.1 Maintenance
A computerized History and Maintenance Planning System (CHAMPS) was ,
instituted to retrieve and track activities associated with maintenance.
The CHAMPS maintains and updates corrective maintenance (CM) and preven-
tive maintenance (PM) status, including scheduling, Maintenance Request
Forms (MRF) and Operation Verification Forms (OVF) after completion of
maintenance activities. The CHAMPS also provides information related to j
the post-maintenance testing requirements and PM frequencies, and speci- i
fies operational functional checks and surveillance tests. l
l
_ _ - _ . - . _ . -. . - - . - _ _ . -_
. .
43
Due to recent jurisdictional changes of PM program, some of
PM activities appeared to be either not documented or not performed,
particularly on various station fans. Details of the findings are
discussed in Section 3.5.3.
No unacceptable conditions were identified.
6.2 Surveillance
The inspector evaluated surveillance testing as a system and various
implementation procedures to verify that surveillance testing met the
requirements specified in Technical Specifications and intended objec-
tives.
The inspector noted that the licensee instituted Critical Equipment Moni-
toring System (CEMS) to monitor the critical equipment status. The
CEMS is in the process of implementation and at present the critical
valve status information is centrally filed and monitored. Bar-coded
white CEMS status labels were displayed on the valves, whose positions
were filed in the computerized file and were readily accessible. CEMS
labels were noted on electrical components and switchgear as well.
Labelling under CEMS is discussed in Sections 3.3 and 3.5.
All surveillance test data reviewed (see Appendix A) reflected adequate
and appropriate testing to meet Technical Specifications.
6.3 -Quality Assuance and Quality Controls
The onsite QA/QC activities were discussed with operational QA/QC per-
sonnel and QA surveillance reports listed in Appendix A were reviewed.
QC audit reports were reviewed and programmatic implementation was dis-
cussed with the site personnel. QA/QC oversight was discussed with the
QA/QC management. Even though PRA information was not directly utilized
for the QA/QC audit program, the licensee emphasized that the QA/QC
program also prioritized and placed heavy emphasis on important site
activities.
The inspector also observed that QA/QC personnel were knowledgeable of
the plant activities. When a concern on the vendor surveillance program
was raised regarding the safety relief valve "As Found" testing by ,
Wyle Laboratory, the vendor test reports were reviewed by the site QA/QC.
This unresolved item is discussed in Section 4.2. The inspector had no
further questions.
6.4 Modifications
Station Administrative Procedure A-14, " Plant Modifications", Revision
12, April 21, 1986, describes the administrative control mechanisms for
implementing minor modifications, to plant systems or equipment. Proce-
dure A-14 also is applicable to software changes to process computer
_
. .
44
programs. However, plant instrument set points and their changes are
not considered as modifications under the A-14 procedure and are governed
by proced.re A-32a.
Post-maintenance test requirements are set forth in a procedure A-89,
" Modification Acceptance Tests", Revision 2, July 31, 1986, which pro-
vides requirements for the preparation of modification acceptance tests
(MAT). Six modifications involving equipment identified in the PRA
sequences were selected for review. The review and inspection findings
follow.
6.4.1 Emergency Service Water Alternate Control Station
(Mod. No. 1351)
The purpose of this modification is to establish alternate
control stations for the 4 KV emergency circuit breaker for
the B ESW pump and to assure safe shutdown in the event of
a design basis fire.
For MOD No.1351 (PORC review 85-057, May 8,1985), the work -
is in progress. The modification provides manual control of
the B ESW pump motor necessary to supply cooling water to the
6.4.2 Modification of Containment Purge and Vent Valves To
Increase Percent Opening (MOD No. 100, February 6, 1986)
The modification consists of replacir.g a number of valve parts
(shafts, pins, bushing, keys and rings) on eighteen (18) purge
and vent valves to increase the angle of valve opening. The MOD
package included safety evaluation report, construction /
installation documentation and testing.
The purpose was to reduce the time required for inerting and
deinerting primary containment from 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> to nine hours.
The modification increased the opening angle from 37 degrees
to 70 degrees for 6" A0V 2519; 18" A0Vs, 2505, 2511, 2512, and
2520; and 18" A0Vs, 2506, 2507, 2521A, and 25218.
6.4.3. Emergency Service Water System (MOD No. 556,
September 22, 1982
The modification upgraded Emergency Service Water (ESW) and
Reactor Building Closed Cooling Water (RBCCW) interface to
Seismic Class 1. The measure was to correct design deficiencies
in the ESWS. The completed MOD package included safety evalua-
tion report, drawing, completed modification work order, and
post-modification testing records. 3
- .- ___,_ _ _ . _ _ ___ _ _ . __. _ _
. .
45
6.4.4 Downgrading of Primary Containment Purge and Vent Valve
Pneumatic Supplies (MOD No. 1439, November 10, 1986)
The proposed modification was to downgrade the importance of
the safety grade bottle air supplies to the purge valves based
in reportedly low rates of leakage observed when the valve
seats were deflated. However, an engineering evaluation and
subsequent observation of the leakages did not support the
proposed modification; MOD Request 1439 was closed without
the proposed actions.
6.4.5 Addition of A New No. 343 230-13.8 KV Power Transformer
(MOD No. 1398, March 1986)
The modification was made on 220 KV switchyard to add trans-
former, breakers and associated circuits to North Substation.
The objective of this modification was to provide an additional
'(third) startup power feed. The MOD package included:
- SER, September 3, 1985
- PORC Review #85-146, October 10, 1985
- MRF No. 2-856117, 3-8585958
- WO 401261-8131
Operational Verification Form, March 21, 1986
The modification was completed in time to support resumption
of Unit 3 operations following a switchyard transformer
failure in April, 1986.
6.4.6 Removal of Automatic Closing Function of MOV-0498
(M00 No. 2079)
During a review of safe shutdown systems in compliance with
Appendix R of 10 CFR 50, the licensee determined that the
possibility existed for the ESW reservoir isolation valve,
MOV-0948, to close spuriously and to remain closed for certain
fire situations. The closure of MOV-0498 could cause the
emergency diesel generators to trip from loss of cooling water
unless the valve was opened within three minutes. The M0V
provides a flowpath back to discharge pond during ESW opera-
tions, and the closure would interrupt the diesel lube oil
and jacket cooling water flowpath.
Concurrent with the above Appendix R study recommendation,
a separate PRA study on Individual Plant Evaluation (IPE)
insights made a similar conclusion in a memorandum dated
May 15, 1986 which proposed that MOV-0498 be locked-open.
_
. .
46
A final resolution to modify the MOV was documented in a
subject memorandum dated June 4, 1986 from the station manage-
ment.
6.4.7 Modification Documentation
The inspector noted that some modification materials provided
to him did not contain all pertinent information and documents
necessary to evaluate and perform the facility modifications,
such as Safety and Engineering Evaluation Reports, specifica-
tions, and Q-listed part procurement information. In particu-
lar, there were eleven seperate modification packages assoc-
iated with Anticipated Transients Without Scram (ATWS). In
order to evaluate the status of the proposed or on going
modification information, it took several days to search for
the information and supporting documents filed in other places
or misfiled. Most of the information was located during the
inspection. The licensee modification engineer stated that
the inspector's concern with document retrieval would be
carefully evaluatedand the documentation procedure would be
revised if necessary.
7.0 Persons Contacted and Meetings Held
7.1 Persons Contacted
Philadelphia Electric Company
- W. Alden, Nuclear Support, Licensing
C. Behrend, Engineer
R. Betz, Supervisor, Electrical Operations
R. Brower, I&C Engineer
D. Burgard, Inst. Lab Technician
M. Candis, Protection & Control Lab
J. Clupp, Supervisor, I&C Maintenance
J. Cohen, Electrical Engineer
- J. Cotton, Superintendant, Plant Services
K. Cutzer, Electrical Engineer
G. Danison, Performanc Engineer ,
K. Daughter, NPRDS Coorainator '
G. Dawson, Supervisory Performance Engineer
- A. Donell, Station QA Engineer
- R. Fleischman, Manager, PBAPS
- A. Fulvio, Technical Engineer
G. Gellrich, Test Engineer
T. Geyer, Shift Superintendant
J. Gourdier, Maintenance Form Battery Group
S. Hess, Assistant Operations Engineer
C. Kaehler, Senior Reactor Operator
D. Keene, I&C Engineer
. - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _
. ,
47
M. Kelly, Project Engineer
C. Koppenhaver, Systems Engineer, HVAC
- G. Krueger, Mechanical Engineer, PRA
- G. Leitch, Manager, Nuclear Generator Department
R. Lewis, Modification Engineer
- R. Logue, Assistant to Manager, Nuclear Supply
- A. Marie, Mechanical Engineer, PRA
- F. Mascitelli, Modification Engineer
- J. McElwain, Quality Control Supervisor
B. Merryman, System Engineer
H. Metz, Shift Superintendant
- J. Mitman, Engineer, Maintenance
R. Moore, Supervisor, QA Division
A. Porta, Plant Performance Monitoring Engineer
S. Roberts, Operations Supervisor
J. Roe, Plant Operator
C. Rogers, Ele. Field Engineer
E. Sawchuck, System Engineer
M. Schervin, Modifications Engineer
D. Shaulis, Performance Test Engineer
- D. Smith, Superintendant Operations
G. Stanly, Protection & Control Lab
S. Sullivan, Plant Operator
G. Temple, Protction & Control Lab
A. Trapuzzano, QA Auditor
G. Verba, CHAMPS Coordinator
G. Verbidge, Maintenance Engineer
- A. Wasong, Project Engineer
L. White, Shift Superintendant
W. Widner, Shift Superintendant
- J. Winzenried, Staff' Engineer
U.S. Nuclear Regulatory Commission
- D. Clark, PB Project Manager, NRR
- S. Ebneter, Director, Division of Reactor Safety
- R. Gallo, Projects Section Chief
- F. Jape, Region 2, Test Programs Section Chief
- T. Johnson, Senior Resident Inspector
- H. Williams, Resident Inspector
- Individuals, other than team members, present at the exit meeting
on December 19, 1986.
The inspectors also contacted other personnel including, control opera-
tors, assistant control 0;.erators, plant operators, shift technical
advisors, I&C technicians, and maintenance personnel during the course
of the inspection.
.
_ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _
. .
48
7.2 Utility PRA Applications
A meeting was held with the licensee's PRA staff on December 15, 1987 \
to discuss PRA applications.
The licensee began developing its own PRA group during development of
the Limerick PRA. The group worked with GE and SAI in updating this
PRA. Since the establishment of the group, the following activities
have been accomplished:
(1) The Limerick PRA has been maintained current.
(2) Limerick PRA findings have lead to procedural and system
modification.
(4) Limerick EPG's/ trip procedures have been reviewed using PRA ,
insights. l
l
(4) Limerick PRA in generic form was used as input to BWR Owners
Group Technical Specification Improvement Program. l
i
(5) RPS and ECCS Instrumentation needs were reviewed. l
1
(6) A seismic scaffolding issue at Peach Bottom (INPO) was l
assessed using PRA.
(7) Peach Bottom diesel testing philosophy and AC/DC issues were !
revised.
(8) Target safety system unavailability levels at Peach Bottom
were established.
'
(9) Peach Bottom trip procedures were improved.
(10) Fact finding assistance to Sandia on Peach Bottom PRA was provided.
l (11) Fact finding assistance was provided on containment venting NRC
research.
'
(12) PRA training to plant executives and technical staff was developed
and provided.
The current PRA group consists of a group leader and three staff person-
nel. Future plans consist of continued use of the PRA as needs arise
and support of BWR Owners group issues.
The team concluded that the PRA staff, through modest in size, has and
will continue to provide useful support of licensee and Owners Group PRA
and reliability activities.
_ _ _ _ _ _ _ _ _
. .
APPENDIX A
PROCEDURES AND REPORTS REVIEWED i
A.1. Administrative Control Procedures
- Station Organization Chart, June 1,1986
A-2, Administrative Procedure for Control and Use of Documents,
Revision 29, October 9, 1986
A-3, Procedure for Temporary Changes to Approved Procedures,
Revision 7, January 7,1985
A-4, Plant Operations Review Committee Procedure, Revision 21,
September 3, 1986
A-6, Procedure for Control of Drawings and Drawing Logs, Revision
11, December 30, 1985
A-7, Shift Operations, Revision 22, October 8, 1986
A-8, Procedure for Control of Locked Valves, Revision 5, March 14,
1983
A-10, Equipment Location Code List - Station Policy, Revision 3,
September 29, 1986
A-11, Alarm Cards, Revision 6, July 15, 1983
A-14, Plant Modifications, Revision 12, April 21, 1986
A-19, Administrative Procedure for Preparation and Distribution of
Maintenance Procedures, Revision 14, July 3,1985
A-22, Generation of Operational Transient, Off Normal, and Special
Event Procedures, Revision 4, April 5, 1983
,
A-25, Preventive Maintenance Program, Revision 2, December 30, 1983
A-26, Procedure for Corrective Maintenance, Revision 25, October 11,
1985
A-26A, Procedures for Corrective and Preventive Maintenance Using
CHAMPS, Revision 4, February 14, 1986
A-41, Procedure for Control of Safety Related Equipment, Revision 2,
August 31, 1982
- A-42, Procedure for Control of Temporary Circuit Modifications
(TCM), Revision 11, May 20, 1986
_ . _ . -
- - _
- - . . .
. .
i
2
A-43, Surveillance Testing Program, Revision 18, July 8,1986
A-80, Inservice Inspection, Revision 8, January 9, 1986
A-89, Modification Acceptance Tests, Revision 2, August 21, 1986
A-94, Appendix I, Bases for T-99 and T-100 Series TRIP Procedures,
,
Revision 0, October 27, 1983
A-94, Appendix II, T-200 Series Procedures and Bases, Revision 0,
October 27, 1983
'
A-94, Appendix III, TRIP Procedure Flow Chart Format, Revision 0,
October 27, 1983
-
A-94, Appendix IV, Verb List for TRIP Procedures, Revision 0,
October 27, 1983
- A-94, Appendix V, T-200 Series Procedures
A-94, Appendix VI, Verification of TRIP Procedures, Revision 0,
October 27, 1983
A-94, Appendix VII, Validation of TRIP Procedures, Revision 0
A-94, Appendix VIII, TRIP Procedure Abbreviations and Acronyms,
Revision 1, October 26, 1984
A-94, Appendix IX, Writing Style for Flow Charts, Revision 0,
October 23, 1983
ST 1.8, Automatic Depressurization System (ADS) "A" Logic System
Functional
a *
ST 6.4, Main Steam Isolation Valve Closure Timing
ST 6.4.1-1, Main Steam Isolation Valve Closure Timing and Timing
Adjustments
,
ST 9.7, MSIV Partial Closure and RPS Input Functional Test
- ST 10.4, Relief Valve Manual Actuation
,
ST 13.32, Safety and Relief Valve Replacement
ST 13.39, Main Steam Safety / Relief Valve Challenges
i
i+ *=.- -r-w---- 7-, --y,-> w, ...,7,--.w- -, -,,. - - - , . ,, 9 ,, ,wm,-,i---.----g ww.. --..w,m es-_-- ---7 %,.e-m- . _.,,- ., - - -www ----_
1
. .
l
l
l
3
i
ST 14.7A, Response Time Test of MSIV Closure Channels (Shutdown
Conditions)
ST 20.131 LLRT-ADS Accumulator Check Valve and Solenoid Valve LLRT
ST 21.9, MSIV Pilot Valve Solenoid Continuity Test
ASME Code,Section XI, IWV-3413, Power Operated Valves - 1980 Edition,
Winter 1981 Addenda
NPROS for MSIV's
S.3.10.E, Remote Setup of N2 Supply to ADS System
- M 1.6, Relief Valve Replacement
Wyle Laboratories Certification Test Reports for SRVs.
ASME Code,Section XI, IWV-3510, Safety Valve and Relief Valve Tests
- 1980 Edition, Winter 1981 Addenda
NPROS (Nuclear Plant Reliability Data System) for SRVs and ADS from
July 5, 1974 for Unit 2 and from December 23, 1974 for Unit 3.
CHAMPS (Computerized History and Maintenance Program System) for
A.3 QA AUDIT REPORTS
AP 86-96 PL, 10/27/86, Security Screening
- AP 86-80 S0, 10/31/86, Full Power LCO
+ AP 86-50 MEM, 8/15/86, Electrical Maintenance
SP 86-12 MEM, 6/23/86, Mini Outage Surveillance Check
- __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _
-
. ..
4
- AP 86-17, PR, 4/14/86, Periodic Review of Procedures
- '
SP 86-01, MEM, 2/24/86, E2 Diesel Generator Repair
AP 86-06, TR, 1/31/86, Licensed Operator Training /Requalification Program
AP 86-65, TR, 9/12/86, Non-Licensed Operations Personnel Training /
Requalification
AP 86-52 S0, 8/19/86, Radioactive Liquid and Gaseous Effluent Releases
AC 86-31, PR, 8/12/86, INPO Corporate Evaluation Status
AP 85-23, MEM, 5/13/85, Safety-Related Pump / Turbine Maintenance
AP 85-225T, 4/8/85, Surveillance Test Program
- AP 85-73 PL, Emergency Plan and Procedures
AP 85-109 MEM, Local Leak Rate Test / Safety Related Valve Maintenance
AP 85-90 SO, 10/21/85, Locked Valves / Logs and Records
AP 85-37 S0, 8/30/85, Unit 2 Startup and Testing After Pipe Replacement
!
Outage
AC 85-52, 1/13/86, Environmental Qualification of Safety-Related
Electrical Equipment
AP 86-13 ST, 2/28/86, Surveillance Test System
A.4 Emergency Procedures
1.
l *
T-99, Post Scram Restoration Rev. O dated January 14, 1983
l *
T-100, Scram Rev. O dated January 14, 1983
T-101, RPV-Control, Rev. O dated January 14, 1983
T-102, Containment Control, Rev. O dated January 14, 1983
T-111, Level Restoration, Rev. O, dated January 14, 1983
T-112, Emergency Blowdown, Rev. O dated January 14, 1983
T-117, Level / Power Control, Rev. O dated January 14, 1983
- T-200, 18 inch Drywell Vent Procedure
T-210, CRD System Boric Acid-Sodium Tetraborate Injection, Rev. 2
dated May 18, 1984
_ _ _ _ _ _ - _ _ _
. . . . - . .__.- -..
. .
5
.
.
T-211, CRD System Boric Acid-Sodium Tetraborate Injection, Rev. 2
dated May 18, 1984 ,
4
T-212, RWCU System SBL Injection, Rev. 2 dtd July 1,1983
- *
T-220, Control Rod Select Black Bypass Procedure, Rev. O dated
June 24, 1983 .
,
,
,
T-224, ADS Auto Initiation Bypass, Rev. I datd October 28, 1984
E-28, Loss of All A.C. Power on Both Units (Station Blackout), Rev. O
dated June 9, 1982
A.5 System Procedures
S.8.3.A, Electrical System Operations Prior to Starting, Rev. 7 dated
July 24, 1984
! *
S.8.3.B, Electrical Systm Operations During Generator Startup and
Loading, Rev. 4 dated February 10, 1983
S.8.3.D.1, Scheduled Outage of One Off-Site Startup Source, Rev. 7
dated October 24, 1985
S.8.3.D.2, Unscheduled Tripping of 2 Off-Site Startup Source, Rev. 8
- dated October 24, 1986
j
- *
S.8.3.0.3, Unscheduled Tripping of 3 Off-Site Startup Source, Rev. 7
dated October 24, 1986
S.8.3.H, 4KV Fast Transfer, Load Shedding and Sequential Loading on
Bus 1 Undervoltage, Rev. 2 dated October 24, 1986
S.8.3.J.1, Normal Operation of TRW, Rev. I dated December 14, 1983
S.8.3.M Restoration of Offsite AC Power in Event of Loss of Grid,
l Rev. 2, dated October 24, 1986.
,
3
S.8.5.E, Reduce and Isolate Unnecessary DC Loads Following Station
Blackout, Rev. O dated June 9, 1982
S.7.2.M, Utilizing the Torus Dewatering Tank as a Backup to the Unit 2
Condensate Storage Tank, Rev. O dated August 4, 1980
S.3.10.B, Manual Operation of Automatic Depressurization and Relief
Valve System
a
S.3.10.C, Resetting Automatic Depressurization System Following Blowdown
- *
S.17.3.A, Primary Contianment Venting Through SGTS Via the Drywell and
Torus 2" Vent Lines Following a LOCA
S.8.4.A, Manual Start of Diesels, Rev. 14, November 28, 1986
i
'
. ,- . . . . . , . _ - - - . - . - - _ , . - . _ _ , . - . - - - _ - _ , __ - . . - - - _ . - . _ . - -
. .
6
S.8.4. A.E1, Diesel Generator Operation - El Diesel Generator, Rev. 6,
November 13, 1986 *
6
S.8.4. A.E2, Diesel Generator Operation - E2 Siesel Generator, Rev. 8,
November 8, November 13, 1986
S.8.4.A.E3, Diesel Generator Operation - E3 Diesel Generator, Rev. 7,
November 13, 1986
S.8.4. A.E4, Diesel Generator Operation - E4 Diesel Generator, Rev. 7,
November 13, 1986
S 8.4.B, Synchronizing and Loading of Diesel Generators, Rev. 2,
October 24, 1986
S.8.4.C, Auto Operation of Diesel Generators, Rev. 5, November 28, 1986
S.8.4.0, Manual Shutdown of Diesels, Rev. 6, October 28, 1986
S.8.4.E, Routine Inspection of Diesel Generators, Rev 4,
October 28, 1986
S.8.4.F, Cross Connecting 4ky Emergency Busses, Rev. 2, October 6,1986
S.8.4.G, Response to Simultaneous Emergency Diesel Start / Governor
Shutdown Solenoid Energized Signals, Rev. O, April 21, 1983
S.8.4.H, Available Loads for Diesel Generators, Rev. 1, October 15, 1986
S.8.4.J, Diesel Generator Load Restrictions Under Emergency (LOCA/ Dead
Bus) Conditions, Rev. O, dated October 28, 1986
A.6 Surveillance Procedures and Completed Reports
ST 1.8, Automatic Depressurization Systems (ADS) "A" Logic System
Functional
ST 8.1, Diesel Generator Full Load Test, Revision 20, April 21, 1986
ST 8.1.3, Daily Diesel Generator Full Load Test, Revision 11,
October 28, 1986
ST 8.1.4.A, EI Diesel Generator Inspection, Rev. 1, April 9, 1981
ST 8.1.4.B, E2 Diesel Generator Inspection, Rev. 1, April 9, 1981
ST 8.1.4C, E3 Diesel Generator Inspection, Rev. 1, April 9, 1981
ST 8.1.4.D, E4 Diesel Generator Inspection, Revision 1, April 9,1981
_ - - _ _ . _ _ _ _ _ _ _ . . _ - . -- . . - _ - -_ _ - - - - - _. __
. .
7
4
5 *
ST 8.1.6, Diesel Generator Annual Inspection Post Maintenance Test,
- Rev. 1, Novembar 4, 1986 *
- ST 10.4, Relief Valve Manual Actuation
4
ST 11.6.2, Diesel Generator Simulated Auto Actuation and Load Accept-
ance for Unit 2, Rev. 6, completed June 13, 1985
l
ST 11.6.2, Diesel Generator Simulated Auto Actuation and Load Accept-
ance for Unit 2, Rev. 8, July 24, 1985
'
'
ST 13.21 " Emergency Cooling Water Pump, Emergency Cooling Tower Fans,
ESW Booster OPump Operability", Rev. 8
' * ST 13.24, "ISI ESW and SW Check Valve Functional", Rev. 3
j *
ST 13.25-2&3, "ISI Exercise of ESW Air Operated Valves", Rev. 4/Rev. 3
l
ST13.32, Safety and Relief Valve Replacement
!
l
ST 13.39, Main Steam Safety / Relief Valve Challenges (
,
i
ST 20.131 LLRT-ADS Accumulator Check Valve and Solenoid Valve LLRT
'
l and Core Spray Motor 011 Coolers", Rev. O
t
1
'
ST/ISI-6, Appendix S " Emergency Service Water / Emergency Cooling System
Pressure Test", Rev. 0 .
I
j A.7 Maintenance Procedures
l * M1.6, Relief Valve Replacement
,
'
- M-52.1, Diesel Generator Maintenance, Rev. 6, May 14, 1986
- M-52.2, Diesel Engine Maintenance, Rev. 18, September 19, 1986
- M-52.5, Diesel Engine Air Blower Maintenance, Rev. 2, July 9,1985
{
li
- M-52.10, Diesel Engine Main Bearing Changeout, Rev. O, July 23, 1980
l
- M-52.11, Diesel Engine Cylinder Liner Replacement, Rev. 1, July 12, 1985
l
l
- M-52.12, Vertical Drive Inspection and Repair, Rev. O, May 1, 1981
- M-52.13, Diesel Generator 011 Storage Tanks Clean Out, Rev. O,
May 7, 1981 ,
- M-52.14, Diesel Generator Turbocharger Maintenance, Rev. 1, .
August 8, 1984 i
_. - _ _ _ _ _ _ _ . - _ _ . _ . . _ . _ _ _ , _ _ _ _ . ~ . . - _ . . - -
. .
8
M-52.15, Diesel Engine Generator Alignmnt, Rev. 14, June 30, 1982
'
M-52.20, Diesel Generator Air Start System lh" Grove Flexflo Regulators
and Solenoid Operator Maintenanc, Rev. O, September 10, 1986
M-52.21, Dies 1 Generator Jacket Cooling Water Heat Exchanger Outlet
Valves A0-0241 - A thru D Maintenance, Rev. O, September 10, 1986
- M-52.22, Diesel Jacket Water and Air Cooler Coolant Check Valve
Maintenance, Rev. O, September 10, 1986
PM 94.1, Inspection for Asiatic Clams in Plant Equipment Utilizing River
Water, Rev. O, November 8, 1984
A.8 Other Procedures and Reports
System Engineer Responsibility List, August 29, 1986
Safety System Availability Monitoring, January-November,1986
ASEP Data Base Collection Visit to PeCo Peach Bottom Units, SAIC Letter
from J. R. Fragola to A. Kolacylowski, July 26, 1985
=
Draft NUREG/CR-4550, Volume 3, " Reference Plant Accident Sequence
Likelihood Characterization: Peach Bottom, Unit 2
Request for Engineering Services, Emergency Service Water System; ,
PeCo Memo from R. S. Fleischmann to E. C. Kistner, December 3, 1986
- IDCOR Technical Report 23.1.PB, Peach Bottom Atomic Power Station -
Integrated Containment Analysis dated March 1985
=
System Restoration Following Complete Shutdown , Revised June 1,1986
ECCS Pump Room Temperature Response PBAPS PF7/2
Wyle Laboratories Certification Test Reports for SRVs.
- ASME Code,Section XI, IWV-3510, Safety Valve and Relief Valve Tests -
1980 Edition, Winter 1981 Addenda
July 14, 1974 for Unit 2 and from December 23, 1974 for Unit 3.
- CHAMPS (Computerized History and Maintenance Program System) for SRVs
and ADS
Memorandum from R. S. Fleischman to E. C. Kister " Request for
Engineering Services, Emergency Service Water System" dated
December 3, 1986
. .
9
Safety Evaluation of Mod. #1557, Rev. 4, dated April 2, 1986
(hydrolyzing of TORUS room ring headers) '
,
- Appendix R Justification for Continued Operation from S. R. Roberts
to Operations Personnel, Movember 28, 1986
- Instruction Manual for Rodney Hunt Sliuce Gates 6280-C20-26-2.
. c~
-
.-
_ _ _ _ _ _ _ . __ ___ __ _____ ___ __ ____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
. .
APPENDIX B
'
DRAWINGS REVIEWED ,
B.1 Piping and Instrumentation Drawings
- M-314 Service Water System
M-315 Emergency Service Water and High Pressure Service Water
- M-323 Fuel and Diesel Oil System
M-351 Nuclear Boiler
M-365 High Pressure Coolant Injection System
M-367 Containment Atmospheric Control System
- M-368 Radwaste Liquid Collection System Unit 2 and Common
M-370 Radwaste Process and Disposal System - Liquid
M-377, Sheet 1 of 3, Diesel Generator Auxiliary Systems
(Starting Air System), Rev. 2, April 4, 1984
M-377, Sheet 2 of 3, Diesel Generator Auxiliary System (Air
Coolant and Jacket Coolant Systems) Rev. 2, April 4, 1984
M-377, Sheet 3 of 3, Diesel Gnerator Auxiliary Systems (Lube
Oil System), Rev. 2, April 4,1984
M-391 Primary and Secondary Containment Isolation Control Diagram
B.2 Electrical Drawings
- E-1 Single Line Diagram - Station
- E-5 13.8 KV Aux Power System, Unit 2
- E-7 13.8 KV Aux Power System, Unit 3
E-8 Standby Diesel Generators & 4160 Volt Emer Power System, Unit 2
- Startup & Emergency Power Systems
E-12 Standby Diesel Generators & 4160 Volt Emer Power System, Unit 3
- E-26
- E-27
- . -
- E-28 Instrumentation; Uninterruptible AC - Unit 2
,
_________ ______ _
. .
2
E-29 Instrumentation; Uninterruptible AC - Unit 3
'
AB-198809 Station Light & Power and DC Control - 500 KV Substation
- E-187-21 ESW Pump Schematic
- E-187-22 ESW Pump Schematic
E-349 ECWP Discharge Valve Schematic
E-1065 Lighting and Communiction Layout Turbine Building EL
135 Rev. 20
E-1069 Lighting and Communication Layout Control Room, Rev. 14
F-1071 Lighting and Communication Layout Reactor Building EL
91'6" Rev. 20
E-1073 Lighting and Communication Layout Reactor Building EL
135 Rev. 37
E-1074 Lighting and Communication Layout Reactor Building EL
165 Rev. 20
E-1075 Lighting and Communication Layout Reactor Building EL
195, Rev. 11
E-1 Single Line Diagram Station, Rev. F
I
. .
APPENDIX C
Initiating Events, Components, and Human Actions
Selected for Inspection
NUREG/CR-4550,Section V provides a summary of the accident sequences identified
as most significant by the PRA. Ten sequence groups are identified. A sequence
group combines a number of accident sequences having similar characteristics into
one group, simplifying the results. The various combination of initiating events,
component failures, human errors, and human non-recovery actions that are most
likely to lead to sequences occurrence are listed under each sequence group. An
example combination is given below:
IE-TLOSP*ACP-DGN-MA-EDG2*ESW-PSF-LF-103*RA-1J*RA-18J
The combination of events is called a cut-set. This particular cut-set has a
core melt frequency of 8.7 x 10 '. The following are the descriptions of each
of the above terms:
IE-TLOSP = Loss of offsite power (0.07/ year)
ACP-DGN-MA-EDG2 = Diesel Generator #2 out for maintenance (0.0109)
ESW-PSF-LF-103 = Failures of Jacket cooling to Diesel Generator #3 (0.0057)
RA-1J = Failure to recover offsite power in 6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (0.04)
RA-18J = Failure to recover from a diesel maintenance outage by 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (0,5)
The frequency of the entire cut-set is the product of the initiating event
frequency and all the probabilities of the other individual terms. These terms
are generally called " basic events". Each sequence may include hundreds of
cut-sets, but only the dominant cut-sets are displayed. Thus, the " dominant
basic events" are those terms that comprise each dominant cut-set.
C.1 Basic Event Importance
Each basic event in a cut-set must occur for core melt to result. The non-
occurrence of any basic event in a cut-set prevents the cut-set from happen-
ing. Basic event importance is based on the premise that "each basic event
in a cut-set is of equal importance regardless of its individual probability
of occurrence". The importance of a basic event is calculated by summary
frequencies of all the cut-sets that include the basic event. Table C-1
displays the dominant basic event importances for the dominant sequences
groups (one dominant sequence involving an intermediate break LOCA is
excluded). The TB sequences are blackout sequences involving loss of elec-
trical power and the TC sequences involve failure of the reactor to scram.
NUREG/CR-4550 contains further description of the sequences.
,
e .
2
The basic event importances were normalized as follows:
Sum of Dominant Cut-Sets Containing the Basic Event *1000
Sum of all Dominant Cut-Sets
C.2 Basic Event Selection
For the purpose of this inspection the initiating events and basic events
contained in the sequence groups TBUX, TB and TCUX were chosen for inspec-
tion. Those of most interest are summarized below:
Basic Event Inspection Scope
Loss of Offsite Power = Preventative aspects (hardware availability)
and recovery aspects
Battery Failure = Assurance of hardware availability and the
reduction of the potential for common cause !
failure of several batteries
r
Diesel Failure = Assurance of hardware availability and the
reduction of the potential for common cause
_
'
failure of several diesels !
Diesel Maintenance = Assurance that necessary maintenance is done ,
in an effective and timeiy manner l
Operator Error = Assurance that all emergency procedures
related to ATWS & BLACK 0UT can be carried
out effectively
Recovery Action = Assurance that recovery actions from a
specific failure is within the capability
of plant equipment and staff
MSIV's and SRV's = Adequate surveillance and satisfactory [
operating experience to prevent basic events
ESWS = Assurance of system availability; is a vital
support system, especially for diesels
Table C-2 provides the summation of the cut-set frequencies for each basic 1
event as well as the number of cut-sets the basic event appears in.
l
i
>
1
l
'
!
!
f.
. - . , - . . - . . - - - - - -
_ _ - _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ ,
e =
,
TABLE C-1, PAGE 1
DOMINANT BASIC EVENT SUMMARY FOR PEACH B0ff0M UNii 2 - IMPORTANCES
BASED ON CRAff PEACH BOTICR PRA NURE6/CR-4550 VOL. 3
(Intermediate LOCA Sequence Not included)
'
IMPORTANCES FOR SELECTED BASIC EVENi$
Sequences Selected For Reytew 19U1 IB 1001 TCSR TBUP TBU TCSI fBP TCSAR TOTALS
Page Nunter Reference V-20 V-25 V-33 V-41 V-46 V-51 V-57 V 61 V-69
!Nlt!ATINGEVENTS
Loss of Offsite Foner 577 172 1 20 10 8 798
'
TLOSP
furbine Trip 52 16 25 3 to 4 lit
TRTRIP
MSIVClosure 17 10 !! ! B 2 49
Loss of Feedsater 15 9 9 1 5 2 41
- TLFW
Inasvertent Open Relief 1 i
i!0RV
TOTAL SEQUENCE IMPCRIANCE 662 172 37 45 33 10 23 8 8 1000
1
.
i REAC11VliYCONTROL
Mech. Failure of Rods 37 45 23 8 !!4
1 EMERGENCY PCbER
LCSP After Trip 85 4 89
BatteryB2 Failure 662 33 6 701
CCP BAi-LP-62
Cessor. Cause Battery Fall. 662 33 2 2 699
5 0CP LP 24TS
Otesel 6enerator 062 Fall. 99 3 5 105
.
Diesel Generator 063 Fall. 60 0 3 3 66
j Canaan Cause Battery Fall. 39 2 39
i B-ACP-LP-EOS$
DG2 Out Fcr Mitntenance 33 1 2 36
DG3 Out Fcr Maintenance 33 1 2 30
ACF 00N'MA EC63
Nueber of Desinast Sequences Selected for Inspection = 9
N.atercfInitiatingEventsinvolved*5
.
i Number of Basic Events involved * 31
o e
TABLE C-1, PAGE 2
CGM!NANT BASIC EVENT SUMMARY FOR PEACH BOTTOM UNIT 2 - IMPORTANCES
BASED CN ORAFT FEACH BOTTCM PRA NURES/CR-4550 VOL. 3
I!ntersediate LOCA Sequence Not included)
IMPORTANCES FOR SELECTED BASIC EVENTS
Sequences Selected For Revies 1801 IB TCut TCSR TBUP TBU TCSI TBP TCSAR TOTALS
Page Nusber Reference V-20 V 25 Y-33 V-41 V-46 V-51 V-57 V-61 V-69
DPERATOR EFR0RS
Fall to Start SLC by 4 Man 36 18 7 61
SLC-IHE-FS
Fail to Realign SLC(Pfestl 5 2 1 8
SLC-lHE-REL
Fall to Vent Containment 40 8 48
VENT-INE-TC
Fail, to Depress. Prie. 38 37 20 96
DEP-!HE
Fail to Control Fri Level ! !
hcl-!HE il
- Fall. to Start ECW Puep 9 0 10
ECW-IPE-FO-ECWFP
Fail.toinhibitADS 8 9
Ats IHE !M2
liEC0VERfEFRORS
Fall to Fecover OSP by 6 hr 167 8 175
RA-lJ
Fall to Recover OSP by 30 a 0 10 11
RA-!D
Fall to Recover Bat by 30 e 0 6 6
RA-14D
! Fail to Recover DG ty 30 a 3 3
Fatt to Pecover 05 CCF by 2 2
- PA 17J 6 Hours
Fail to Recover 06 by 6 hr 96 5 100
'
Fall to Pecover Fres OG 19 1 20
PA-18J Maint. by 6 he
i
- - -. . - _-
o o
.
TABLE C-1, PAGE 3
DOM!nANT BASIC EVENT SUMMARY FOR PEACH BOTTOM UNIT 2 - IMPORTANCES
BASED ON CPAFT FEACH BOTICM PRA NURES/CR-4550 VOL. 3
lintersediate LOCA Sequence Not included)
IMPORTANCESFORSELECTEDBASICEVENTS
SequencesSelectedForReview TBut TB TCut TCSR TBUP TBU TCSI fBP TCSAR TOTALS
Page Nuoter Reference V 20 V-25 V-33 V 41 V-46 V-51 V-57 V-61 Y 69
OthtRFRONTLINESYSTEMS
Ore SRV Sticks Open 33 8 41
$0RV
Subsequent Closure of M31Vs 18 21 10 4 53 l
HPCI Falls to Start 5 28 4 0 38
] HCI-TLP-FS-20$17
i HPCI Out for Maint. 9 9
hcl-IDP-MA 20$17
RCICFailstoStart 0 10 11
RCI-TDP-FS 20538
$UFPORTSfSTEMS
- Fail. of Jaclet Cooling to 31 2 33
E!W-FSr-LF 102 DG2
Fall, of Jacket Cooling to 31 1 2 34
ESW-PSF-LF-103 D63
. ESuS MOV-0498 Closed Due to 9 0 10
'
, E!W FSF-LF 8 Maint.
4
i
!
l
l
1
i
f
I
!
.:
1
!
l
i
..
_-- . _ _ . _. ._. . _ _ _ _ _ _ _ _ _ _ __
O o
TABLE C 2 FA6E 1
DOMINANT SASIC EVENT StlRMARY FOR PEACH 90ff0M UNIT 2
BASED ON ORAFT PEACH IOTTOM PRA NURE6/CR 4550 VOL 3
lintermediate LOCA Sequence Not included)
SUMMAi!0N OF CUT SET FRE8UENCIES FOR SELECTED 9451C EVENTS
NuntEROFCUTSETCONTAININGTHEPASICEVEntS
Se4uencesSelectedForReview 1901 IB TCUI ICSR IBUP 190 iCSI itP TCSAR TOTALS
Page Nueter Ref erence V 20 V-25 V-33 V41 V 46 V Si V 57 V41 V49
INii!ATINGEVENTS
Loss of Offsite Foner 5.3X-061.5BE46 6.2M-09 2.61E47 9.63E48 7.77E48 7.32E46
TLOSP 1 14 1 2 7 14 39
Turbine Trip 4.90E47 1.51E47 2.34E47 2.4M48 9.60E-08 3.64E48 1.02E46
TRTRIP 1 3 6 1 2 4 17
MS!VClosure 1.60E47 9.40E-08 9.74E48 8.00E-09 7.40E48 1.84E48 4.52E47
1RS!vt i 2 3 1 1 2 10
Loss of Feedeater 1.40E-07 8.30E48 8.55E48 7.00E49 4.30E48 1.60E-08 3.75E47
TLFN 1 2 3 I i 2 10
Inadvertent Open Relief 1.0X48 1.00E48
!!0RV l i
TOTAL SEQUENCE PROBABILITY 6.09E461.58E46 3.44E47 4.17E47 3.00E47 9.63E48 2.13E47 7.77[48 7.00E-08 9.lBE46
TOTAL NUMBER OF CUT SETS 4 14 9 12 5 7 4 14 8 17
REACilVlifCONTROL
Rech. Failure of Rods 3.44E47 4.l?E47 2.13E41 7.0K48 1.04E46
9 12 4 8 33
ERER6ENCY PONER
LOSP After Trip 7.8X47 3.90E48 8.19E47
LDSP 3 3 6
Battery 82 Failure 6.0E 06 3.0M47 5.70E48 6.44E46
0CP4AT-LP 12 4 5 3 12
Cceeon Cause Battery Fall. 6.00E-06 3.00E47 1.50E48 1.60E48 6.41E46
8 DCP LP4ATS 4 4 I i 10
Diesel Generator 062 Fall. B.I6E47 2.4tE48 4.24E48 9.63E47
ACP464 LP4062 7 3 7 17
Oletel Generator 063 Fall. 5.50E47 1.10E 09 3.21E4B 2.64E48 6.lM47
ACP464 LP E063 5 1 3 5 14
Cocoon Cause Battery Fall. 3.46E47 1.60E48 3.62E47
lACPLPEtGS 2 1 3
062 Out For Maintenance 3.07E 07 8.00E49 1.44E48 3.29E47
ACP464 MA ED62 3 1 3 7
063 Out For Raintenance 3.07E47 3.00E48 1.44E48 3.51E47
ACP46N-RA-E063 3 3 3 9
Nuder of Doeinant Sequences Selected for Inspection a 9
N.M er of Initiatteg Events involved a 5
Aaeber of Basic Events Involved a 31
_ - _ _ _ _ _ _ _ - _ _ _
o o
!
1
IAttt C 2, PAGE 2
DOMINANTBASICEVENTSUMMAAYFORPEACH80fiOMUNIT2
l BAStB 04 DRAFT PEACH 80ff0M PRA NURES/CR 4550 V0'. 3
(latermediate LOCA Sequence IIst included)
SUMAfl0N OF CUT Sti FRt0UtNCl[$ FOR SELECit8 BASIC (VENTS
- EMBER OF CUT Sti CONTA!N!NG THE BASit (VENTS
l
l
Sequences Selected For Revlee 1801 TB 1001 iCCR T8UP 18U TCSI 18P TCSAR TOTALS
Fage Nuoter Reference V-20 V 25 V 33 V 41 V 46 V 51 V 57 V-61 Y 69
OPERAf0ACARORS
Fall. to Start SLC by 4 Min 3.29E07 1.66E-07 6.25t-08 5.58E-07
SLC lHC FS 3 3 6 12
Fall. to Realign SLC(Pfest) 4.25[-08 2.20t-08 8.30E 09 1.28[08
SLC INE REL i 1 2 4
i Fall to Vent Containeent 3.7tt 07 7.08E-08 4.42E07
VENT-INE it 4 8 12
Fall. to Depress Prie. 3.47[ 07 3.44[ 07 1.88t-07 8.79t 07
DEP IHE 2 9 4 15
Fall to Control Pri. Level 5.80E-09 5.80E 09
HClIHtIL i 1
Fall. to Start (CN Puep 8.40E 08 4.20E 09 8.82t08
Fall.toinhibitADS 7.08t 08
ABS INE !NH2 8
REC 0VERYtRRORS
Fall to Recover OSP by 6 hr 1.53t06 7.77[ 08 1.6tt 06
RAlJ 14 14 28
Fall to Recover OSP by 30 e 1.10t 09 9.63[ 08 9.74[08
RA lO I 7 8
Fall to Recover Bat by 30 e 1.10t-09 5.70t 08 5.81t08
l
R4 140 1 5 6
Fall to Recover DG by 30 e 2.43t 08 2.43t08
RA160 3 3
Fall to Recover DG CCF by 1.60E08 1.60[08
RA 17J 6 Hours 2 2
Fall to Recover 06 by 6 hr 8.80E 07 4.18E08 9.22t07
RA-161 8 8 16
Fall to Recover Free C6 1.74t 07 8.00E 09 1.83t07
RA 18J Paint by 6 hr 2 2 4
(
!
i
_ _ _ _ . - _ _ _ _ _ .
O e%
TABLE C 2, PAGE 3
90RINANT 84 Sit (VENT SUMARY FOR PEACH B0iiOM Unit 2
BASED 04 ORAFT PEACH 901 TOM PRA NURil/CR 4350 VOL. 3
lintermediate LOCA lequence Not Included)
$UMAi!04 0F CUT Sti FREQUENC!!S FOR SELECTED DASIC (VENTS
NUMetR OF CUT Sti CONTAINING THE BAllt Evthil
Sequences Selected For Revies 19U1 il TCut TCSR itur 100 iCSI itP TCSAR TOTALS
Page Ik.eber Ref erence V20 V 25 V33 V 41 V 46 V SI V 57 V 61 Y 69
Diktt FRout LINE SYSitMS
0.1eSRVSticksOpen 3.0M 07 7.77t-00 3.7K-07
$0RV 5 14 19
Subsequent Closure of R$1Vs 1.6ft-07 1.09t 07 9.6 M 08 3.64(-00 4.02[ 07
CMSIVA 4 6 2 4 16
kPCIFallstoStart 4.60E002.5ft-07 3.93t 00 2.30E09 3.47t07
HCI TOP FS 20S37 4 5 4 4 17
HPCI Qut for Maint. 7.9M-00 7.9M-00
hClTDPMA20$37 3 3
RCICFallsto$ tart 1.lM 09 9.63t 00 9.74t-00
RCI itP F$ 20$30 1 7 0
SUPPORTSYlitMS
Fail of Jacnet Cooling to 2.88t07 1.44[ 00 3.02t07
(5N PlF LF 102 062 3 3 6
Fall,ofJacketCoolingto 2.08t07 1.20t00 1.46t00 3.15(07
Ele-PSF LF 103 063 3 1 3 7
ISalMOV0490ClosedOveto 0.40( 00 4.2M 09 0.02t 00
ESN PSF-LF 8 Maint. 1 i 2