ML18151A512
| ML18151A512 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 12/15/1988 |
| From: | Belisle G, Julian C, Mellen L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18151A513 | List: |
| References | |
| 50-280-88-32, 50-281-88-32, NUDOCS 8812220026 | |
| Download: ML18151A512 (77) | |
See also: IR 05000280/1988032
Text
e
UNITED STATES
e
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
ENCLOSURE 2
Report Nos.:
50-280/88-32 and 50-281/88-32
Licensee:
Virginia Electric and Power Company
Richmond, VA
23261
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.: DPR-32 and DPR-37
Inspection Conducted:
September 12-16, September 26-30, and November 14-18,
1988
- /1/
..
Inspectors:
1 J.
1 /S~_,;_,/ :_____->
G. A. Belisfe~ Team Leader*
r--~ s.
1Yrli&C-~
ct. S. Mellen, Assistant Team Leader*
Team Members:
R. Bernhard*
T. Cooper
R. Gibbs
R. Moore
M. Thomas
Date Signed
Accompanying Personnel:
F. Witt, Office of Nuclear Reactor
Regulation
Westec *contractor Personnel:
T. DelGaizo*, S. Kobylarz*
Approved
- conducte~ iJspection on Novemb~r 14-18,
By: ~
A. ~.,,,
Caudle A. Julian, Chie~
Operations Branch
.
Division of Reactor Safety
8812220026 881215
ADOCK 05000280
G
PNU
1988
/2//5/<tO
&te s*;gned
e
2
SUMMARY
Scope: This special, announced Safety System Functional Inspection (SSFI.) was
performed to assess the operational readiness of the Service Water (SW) and
Recirculation Spray (RS) systems to meet their intended design function under
all postulated conditions. The licensee 1 s tiperational and management controls
were evaluated in the following functional areas:
Design Control
Operations
Maintenance
Surveillance
QA/QC
Inspection Objective:
The inspection objective at Surry was to assess the
ope rat i ona 1 readiness of the SW and RS systems.
The assessment included
determining the following:
capability of the systems to perform their safety functions as
required by the design basis
adequacy of operations to ensure the systems are being operated
properly
adequacy of maintenance to ensure the systems are being maintained
properly
adequacy of surveillances to ensure the systems are being tested
properly
adequacy of QA/QC activities to ensure the systems are being reviewed
properly.
Acronyms used throughout this report are listed in the Appendix B.
Results of Inspection Findings:
Eight apparent violations, two apparent deviations, three URis, and sixteen
IFis were identified as follows:
Apparent violation 280,281/88-32-01: Failure to adequately establish a
design contra 1 program that meets A_NSI N 45. 2-11 requirements, Paragraphs
4.A.1.a, 4.A.l.b, 4.A.l.c, 4.A.l.d, 4.A.2.a, 4.A.2.b, 4.A.2.i .(2), and
4.A.6.
Apparent violation 280,281/88-32-02: Failure to exercise service water
valves to the position required (closed to open), paragraph 4.0.1.
Apparent violation 280,281/88-32-03:
Failure to include appropriate
qualitative or quantitative acceptance criteria into site procedures,
paragraphs 4.A.2.d, 4.A.2.e, 4;A.2.g, 4.C.l, and 4.0.2.c.
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3
Apparent violation 280,281/88-32-04:
Failure to establish adequate
procedures for torquing fasteners, paragraph 4.C.l.
Apparent violation 280,281/88-32-05:
Failure to establis~ adequate
measures to maintain material traceability, paragraph 4.C.l.
Apparent violation 280,281/88-32-06:
Failure to perform testing to
demonstrate operability, paragraph 4.C.1.
Apparent violation 280,281/88-32-07: Failure to correct conditions adverse
to quality promptly, paragraph 4.C.4.
Apparent violation 280,281/88~32-08:
Failure to document corrective
actions for identiffed deficiencies, paragraph 4.E.
Apparent deviation 280,281/88-32-09: Failure to meet commitments to the
NRC Generic Letter 83-28 for including vendor manua 1 requirements into
site proceduresi paragraphs 4.A.l.n, 4.8.3, 4.C.l ~nd 4.C.2.
Apparent deviation 280,281/88-32-10: Failure to meet UFSAR commitment
(IEEE-279)
to
have
indication of bypassed engineered
safeguards
actuations, paragraph 4.A.2.k.
Unresolved Item 280,281/88-32-ll: NRR to determine if Surry can meet GDC-2
requirements, paragraph 4.A.1.1.
Unresolved Item 280,281/88-32-12: Licensee, to evaluate lack of -voltage
drop/voltage profile analysis for station 125 VDC batteries, paragraph
4.A.2.c.
Unresolved Item 280,281/88-32-13: Licensee to'eval-uate potential loss of
combustion air to ESW diesels due to ceiling damper failure, paragraph
4.A.2.j.
Inspector Followup Item 280,281/88-32-14: Clarify procedure SUADM-LR-12
relative to performing safety evaluations, paragraph 4.A.1.i.
Inspector* Followup
Item 280,281/88-32-15:
Items
identified during
observations and system walkdowns, paragraphs 4.A.l.m, 4.A.1.o, and
4.A.l.p.
Inspector
Followup
Item 280,281/88-32-16: Clarify testing the
batteries without the charger being connected, paragraph 4.A.2.f.
IRspector Followup Item 280,281/88-32-17:
Update electrical drawing
11448-FE-lG to accurately reflect as built conditions,
paragraph
4.A.2. i .(1).
Inspector Fo 11 owup Item 280 ,281/88-32-18: Wiring discrepancies between
drawings and as built conditions in the main control boards, paragraph
4.A.4.
. (*
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4
Inspector Fo 11 owup Item 280, 281/88-32-19: Eva 1 uate the use of butterfly
valves for throttling, paragraph 4.B.4.
Inspector Followup Item 280,281/88-32-20: Correctly maintain*operator logs
to accurately reflect personnel available, paragraph 4.B.5.
Inspector Followup Item 280,281/88-32-21: Update plant procedures and
UFSAR to accurately reflect updated calculations, paragraph 4.8.6.
Inspector Followup Item 280,281/88-32-22: Verify SW valve testi,ng and
method to keep RSHXs dry, paragraph .4.B.8.
Inspector Followup Item 280,281/88-32-23: Evaluate installing commercial
grade gauge in safety-related applications and maintain calibration
records for this gauge, paragraph 4.C.l .
Inspector Fo 11 owup Item 280, 281/88-32-24: Incorporate MDVATS testing for
SW and CW valves, paragraph 4.C.3.
Inspector Fo 11 owup
Item 280, 281/88-32-25:
Revise UFSAR to accurately
reflect correct test frequency for ESW pumps, paragraph 4.D.2.a.
Inspector Followup Item 280,281/88-32-26: Provide t'raining for personnel
on use of PT25.3.C data taking, paragraph 4.0.2.d.
Inspector Followup Item 280,281/88-32-27: Include tolerances for ESW pump
flow in appropriate procedures, paragraph 4.b.2.e.
Inspector Fo 11 owup
Item 280, 281/88-32-28: Revise procedures to assure
operability of control room chiller pumps, paragraph 4.D.3.
Inspector Followup Item 280,281/88-32-29: Perform corrective action to
close DR 1-88-0998, paragraph 4.A.2.h .
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TABLE OF CONTENTS
. FOR
REPORT DETAILS
e
1.
Persons Contacted ..................... ; . . . . . . . . . . . . . . . . . . .
1
2.
Exit Interview ..... .' ...... * .......................... :.....
I
3.
System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
4.
Detailed Inspection Findings..............................
2
. A.
Design Control .................. * .......... -. ......... .
2
2
1.
Mechanical Design ........ ; ........... , ......... .
a.
Design Calculation ME-180............. ... ..
2
b.
Design Calculation ME-179........... ... .. . .
4
c.
Design Calculation ME-166.............. ....
5
d.
D~sign Calculation ME-187 ............ , .~.,.
6
e.
Intake Canal Level Instrument Calibration..
6
f.
Demon strati on of ESW Pump Rated Fl ow.......
7
g.
HX Fouling ................................ ,
8
h.
Environmental Qualification of Equipment .... 13
i.
Design Modification Process.:..............
13
j.
Design Control Packages .................... 15
k.
Chiller Condenser Pump NPSH ............ ***-
.15
1.
Protection Against Natural Phenomena.......
16
m.
Maintenance and Housekeeping Items ..... :... 16
n.
RSHX Replacement ........................... 16
o.
System Wa 1 k.down............................
17
p.
SW Pumphouse Walkdown ...*.................. 19
2.
Electrical Design
a.
Minimum Design ESW Pumphouse Ambient
Temperature ............................ ; . . . . .
21
b.
Maximum Design Ambient Temperature ......... 23
c.
Adeq~acy of Class IE 125 Volt DC System
Voltage ...... .-.............................. 24
d.
ESW Pump Diesel Battery Procedures ......... 25
e.
Battery Specific Gravity Surveillance ...... 27
f.
Batteries Never Tested Without Charger ..... 27
. g.
Electrical Maintenance Procedure Minimum_
Specific Gravity ....... * .................... 28
h.
Seismic Design Qualification for ESW Pump
Equipment ..... _............................. 29
i.
Design Ve~ification Calculation for Class
lE Station Battery Sizing .................. 31
,.
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Table of Contents
2
j.
Potential Loss of Combustion Air on
Damper Single Failure ...................... 33
k.
Lack of Continuous Indication of Bypass of
Engineered Safeguards Actuation ........... :
34
3.
Chemical Design ................................. 34
a.
SW System Inspection ....................... 34
b.
Service Water Chemistry .................... 35
c.
Surveillance and Inspection Program ........ 36
4:
Configuration Control ........................... 37
5 . * Health Phys i cs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3 9
6.
Off-site Engineering ............................ 39
B.
OPERATIONS...........................................
39
1.
SNSOC Reviews of Procedure Deviations ........... 40
2.
ESW Diesel Engine Fuel Oil System ............... 40
3.
Operating Procedures for SW and ESW Systems ..... 41
4.
Use of Butterfly Valves in the SW ,System ........ 42
5.
Minimum Shift Crew Coverage ..................... 43
6.
Operator Training for SW and ESW Systems ........ 44
7.
Control Room/Relay Room Ventilation System
Chiller Condenser Problems ...................... 45
8.
Water Found in the RSHXs ........................ 47
9.
SW and ESW Panel Configuration .................. 47
C.
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
48
1.
Review of Maintenance in Progress and Complete
Maintenance Work Orders ......................... 48
2.
Preventive Maintenance .............. ~ ........... 53
3.
Predictive Analysis.............................
55
4.
Trending and Root Cause Analysis of Component
Failures ........................................ 56
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Table of Contents
3
D.
Survei 11 a nee........ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
57
1.
SW System Valve Testing .............. : .......... 58
2.
SW System Pump Testing ............. ~ ............ 58
3.
Control Room Chiller Pumps .......................
61
E.
QA/QC.................................................
62
Appendix A
Appendix B
Lice~see Employees
1.
Persons Contacted*
Refer to Appendix A
2.
Exit Interview
r .-
e
The inspection scope and findings were summarized on November 18, 1988,
with those persons indicated in Appendix A.
The inspectors described' the
area~ inspected and discussed in detail the inspection findings previously
listed. The licensee did not identify as proprietary any of the material
provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Revisions to the
findings were discussed with Mr. Benthall of your staff on December 2,
December 12, and December 14, 1988.
3.
System Description
The
CW system supplies cooling water to the main condenser.
Water is
drawn from the James River through eight screenwe 11 s to eight CW pump
inlets (one screenwell per CW pump).
The CW pumps discharge water through
eight 96-inch lines up over a berm and down into the upper intake canal.
The CW pumps are powered from non-vital 4160 V AC busses and each pump
discharges 210,000 gpm.
Each CW pump discharge line has a VP system
(assists getting water from the pump discharge up over the berm and down
into the upper intake can a 1) and a VB system ( prevents water from
siphoning from the upper intake canal back to the James River if power is
lost to the CW pumps).
The upper intake canal is 1.7 miles long and at
the time of the inspection, the minimum TS operating *level was 18 feet
above MSL.
The licensee was contro*lling the upper intake canal level at
27 feet during the inspection due to concerns identified with the CCWHXs.
Water flows from the upper intake can a 1 to the high 1 eve 1 intake structure
for each unit.
Water then flows by gravity through each unit's
condensers, through the associated discharge tunnel and back to the James
River.
Each unit's high level intake structure has a bubbler type level
transmitter which uses backpressure on the sensing line to determine the
upper intake canal's level.
When the upper intake canal drops below the
TS required level, the turbine trips, the 96 inch CW inlet and outlet MOVs
to the condenser close and SW is isolated except for water to the RSHXs,
control room chillers, and the charging pump SW system.
The safety-related SW system branches off from the CW lines between the CW
inlet MOVs to the condenser and the upper intake canal.
The SW system
supplies water to the CC, RS, and BC HXs, control room and relay room air
conditioning unit chiller-condenser, charging pump SW system, station VP
seal water coolers, 555-ton air conditioning unit chiller-condensers, and
4.
e
e
2
river water makeup pumps.
The SW system can also be supplied water from
three diesel driven ESW pumps at the river water pumphouse.
The~e pumps
take a suct.i on from the James River and discharge to the upper i nt;ake
canal through their-own separate discharge lines.
Detailed inspection Findings
A.
Design Contro 1
.
.
During the inspection~ th~ licensee was asked if an 18 foot level in
the upper intake canal provided sufficient water to perform all
required safety functions.
They were also asked to provide the
design basis calculation for this level. Th~ licensee responded that
a search for the original calculitions failed to produce any design
basis calculations on canal inventory.
Consequently, calculation
ME-179 was performed and issued on September 9, 1988, and changes to
the UFSAR were issued on or about that date .. The p 1 ant had been
operating with the upper intake canal level at 27 feet due to earlier
concerns raised by the resident inspectors.
Calculation ME-180 was
performed and issued on September 9, 1988, and provided the basis for
operation at the 27 foot level.
1.
Mechanical Des_ign
a.
Design Calculation ME-180, SW Inventory Impact of the Condenser
Isolation Valves, Revision 1, dated September 9, 1988, Operation
at 27 Foot Intake Cana 1 Leve 1
The current minimum TS water level for the upper intake canal
is 18 feet.* At this level, according to the UFSAR, the upper
intake cana 1 contains sufficient water inventory to supply
essential post~ac,ident cooling loads for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> without upper
intake canal make-up;
A licensee SW system design review
performed prior to the SSFI i dent ifi ed that the upper intake
canal low-level instruments and trip circuitry, which isolate
non-safety cooling loads to preserve canal inventory, were not
safety grade or single failure- proof.
Calculation ME-180 concluded that from a 26.5 foot initial canal
level,* post-accident canal level remained above the minimum
level (16 feet) needed for acceptable SW flow to the RSHXs.
Calculation ME-180 provided the justification for continued
operation.
Calculation ME-180 assumed that the CW system would be isolated
by operator action 30 minutes following the accident's start,
that one ESW pump would be started after 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, that two RSHXs
would be isolated after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and that the third RSHX would
be isolated after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
However, this calculation was
insufficient as a justification for continued operation for the
following reasons:
. ('
(1)
3
,.
o"
e
The upper intake canal inventory loss by siphoning back
through the 96 inch CW inlet lines was not. considered.
These lines are provided with non-safety related VBs which
must function to break the siphons. If both VBs on any of.
the eight CW inlet lines do not function, canal inventory
will decrease until the siphons are automatically broken by
exposing the CW piping at a canal level of approximately 19
feet.
(2)
Loss of inventory through the BC and CC HXs was not
considered.
These nonessential loads are also isolated by
the non-safety low-level trip circuit.
Flow through these
components during the 30 minute delay for operator action
needed to be included .
(3)
The accuracy of the level instruments measuring the initial
upper intake can a 1 1 eve 1 was
not included.
Because
combined errors constitute over 1 foot of canal level, an
observed level of nearly 28*feet is needed to assure an
actual initial level of 26.5 feet. * This is further
discussed in paragraph 4.A.l.e.
(4)
The assumed design rated flow (15,000 gpm) for the running
ESW pump has not been demonstrated.
The current periodic
test of the ESW pumps is desi-gned to verify approximately
12,000 gpm.
River level (i.e., low level) and pipe fouling
may further reduce fl ow.
This is further discussed in
paragraph 4.A.l.f.
(5)
Design pipe fouling factors were not representative of
actual system conditions. Substantial fouling was observed
in the SW system.
This is further discussed in paragraph
4.A.1.g.
In a postulated LOCA with a coincident LOOP and an initial upper
intake canal level at 27 feet (as measured by installed
instrumentation), upper intake canal level could decrease below
the minimum canal level (16 feet) necessary to achieve required
minimum SW flow (6000 gpm) to the RSHXs.
Failure to include required design basis information in Design
Calculation ME-180 i.s contrary to the requirements of 10 CFR 50
Appendix B Criterion III and the licensee 1 s commitment to
Regulatory Guide 1.64 and ANSI N45.2.ll.
This is collectively
combined with additional design basis inadequacies and is
identified as apparent violation 280,281/88-32-01.a .
4
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e
b.
Design Calculation ME-179, SW Loss of Inventory Design Basis,
Revision 1, dated September 9, 1988, Operation at 18 Foot Intake
Canal Level
Calculation ME-179 was prepared to develop an inventory profile
as a design basis for the SW upper intake canal once the canal
low-level instrumentation and trip circuitry are modified to
meet
safety grade
and single failure requirements.
The
calculation concluded that, with an 18 foot initial upper intake
canal
level, post-accident canal level remained above the
minimum level (16 feet) needed for acceptable SW flow to the
Calculation ME-179 assumed that all nonessential cooling loads
would be isolated 1 minute after the start of the accident, that
1 ESW pump would be started after 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, that 2 RSHXs would be
isolated after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; and that the third RSHXs would be
isolated after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
However, this calculation failed to
demonstrate that the 18 foot level provided needed inventory for
the following reasons:
(1)
The accuracy of the level instruments measuring the initial
upper intake canal level was not included.
These combined
errors constitute over one foot of canal level.
This is
further discussed in paragraph 4.A.l.e.
(2)
The assumed design rated flow (15,000 gpm) for the running
ESW pump has not been demonstrated.
The periodic test of
the ESW pumps is designed to verify approximately 12,000
gpm.
River level (i.e., low level) and pipe fouling may
further degrade flow.
This is further discussed in
paragraph 4.A.l.f.
(3)
Design pipe fouling factors were not representative of
actual system conditions. Substantial fouling was observed
in the SW system. This is further discussed in paragraph
4.A.l.g.
In a postulated LOCA with a coincident LOOP, upper intake canal
level at 18 feet (as measured by the installed instrumentation)
could decrease below the minimum level (16 feet) necessary to
achieve required minimum SW flow (6000 gpm) to the RSHXs.
The failure to include required design basis information in
Design Calculation ME-179 is contrary to the requirements of 10
CFR 50 Appendix B Criterion III and the licensee's commitment to
Regulatory Guide 1.64 and ANSI N45.2.11.
This is collectively
combined with additional design basis inadequacies and is
identified as apparent violation 280,281/88-32-01.b.
'.
5
(I *
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c.
Design*calculation ME-166, Intake Canal Inventory, Revision 0,
dated October 10, 1988, Operation at 23 Foot Intake Canal Level
Calculation ME-166 was prepared in _October 1988 to supplement
( and subsequently supersede) ca lcul ati ons ME-179 and ME-180.
Calculation ME-166 evaluates a number of potential* single
. failure events and operator reaction times in order to establish
the design basis inventory requirements for the intake caQal.
Th~ calculation concluded that with a 22 foot intake canal level
and the most limiting single failure, canal level remained above
the minimum level (revised by this calculation to 17 feet)
needed to assure acceptable SW flow to the RSHXs.
(Note:
The
Licensee included an additional 1 foot margin and established
the minimum intake canal level at 23 feet).
Calculation ME-166 made several of the same assumptions made in
ME-179 except that ESW pump~ did not start until 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> into
the accident (with flow at the IWP alert level of 14,100 gpm
each), that the discharge channel elevation (river level) was
-1.3 feet, and that a ~assive vacuum break.er will be installed
to preverit siphoning through the
CW inlet lines.* After*
reviewing this calculation, the inspectors determined that this
calculatiori would adequately document establishing 23 feet as a
minimum TS level, provided the following discrepancies were
resolved:
(1)
The assumption that BCHX flow would be design flow (12,000
gpm) at a canal
level of 18 feet appeared to be
nonconservative.
The flow figure used (12,000 gpm) was
taken from the original design basis and was not consistent
with more conservative methods used to calculate flows in
previous (ME-179 and ME-180) calculations.
(2)
The assumption that CCWHX flow would be design flow (9,000
gpm) at a can a 1 1 evel of 18
feet appeared to be
nonconservative.
The flow figure used (9,000 gpm) was
taken from the original design basis and was not consistent
with m6re conservative methods used to calculate flows in
previous (ME-179 .and ME-180) calculations.
(3) The design input that- CW flow would be 840,000 gpm per
condenser was taken from a 1967 preconstruction Stone &
Webster calculation which did not sufficiently document its
basis.
It was not based on as-built information on the
original condenser or on their replacements.
The validity
of this flow rate needed to be confirmed.
On November 11, 1988, the l1censee issued Revision 1 to ME-166.
The revision indicated that assumptions on BCHX and CCWHX flow
were nonconservative but that CW flow was so conservative that
e
6
the end result of the revision, m1n1mum canal level, was reduced
from 22 feet (Revision. 0) to 21.25 feet {Revision 1).
Calculation ME-166 was a state-of~the-art calc~lation, an.
improvement over prior comparable calculations,. and possibly the
first thoroughly documented design basis for canal level in the
life of the* plant.
In addition, since ME-166 was part of a
Design Control Package (DCP), it will be
subject to a design
verification which had not* been conducted at the time of
0the
NRC
1 s inspection. Nevertheless, Calculation ME-166 demonstrated
. that the design contro 1 process needs to be imp roved even
fufther with regard to confirmation of design input and design
assumptions.
The failure to use conservative flows for the BCHX
and CCWHX and using an unconfirmed flow for the CW system is
collectively identified with additional examples of failure to
include iequired design basis information ~nd is identified as
apparent violation 280,281/88-32-01.c.
d.
Calculation ME-187, Pressure Drop Due to Marine Growth in RSHX
Inlet SW Piping Upstream of Valves SW-MOV-203, Revision 0, Dated
Septemb~r 9, 1988, SW System Fouling Fattors
Calculation ME-187 was performed to determine fouling factors to
be used in determining SW flow to RSHXs based upon marine growth
and
fouling. observed during * SW
valve maintenance. *. The
calculation used
methodology
and
information
from
Crane
Technical Paper 410.
One step fo. the methodology requires
determining the factor
11e/0 11 which is the ratio of *fouling level
(
11 e
11 ) divided by pipe diameter (
110
11 ). The calculation; however,
u~ed pipe diameter in inches rather than feet.
Pipe diameter
11 0
11 , as used in Crane T.P, 410, is defined as diameter in feet .
. This error might have introduced a large inaccuracy in the
calculated fouling factor.
The
11e/D
11 factors were subsequently
combined in another ratio which tended to minimize the
inaccuracy introduced in the calculation.
The failure to use appropriate design input is collectively
combined with additional examples and constitutes apparent
violation 280,281/88-32-01.d.
On November 11, 1988, the licensee issued Revision 1 tci ME-187
which. confirmed the. fact that the change to the ca lcul at ion
output was minimal because ratios tended to cancel the errors.
e.
Intake Canal Level Instrument Calibration
The upper intake canal level transmitter performs an essential*
safety function in that it is used to isolate non-safety loads
for preserving the minimum intake cana 1 water inventory for
essential SW use.
These instruments were not designated as
f.
e
7
safety related in the original design and therefore, the
instrument accuracy was not determined.
Additionally, their
calibration was not controlled to assure an adequate set point
to achieve the required TS limit.
The current Rosemount 1152 upper intake canal level instruments
are calibrated for a canal level trip point of 19 feet.
Calculation EE-0041,
Surry Intake Canal
Level Transmitter
Accuracy, Revision 0, dated September 16, 1988, indicatea a
potential error of plus or minus 11.835 inches. There was also
the potential for an additional 0.91 inches. inaccuracy due to
density changes (salinity and temperature) in the canal water,
for a total potential inaccuracy of 12.745 inches.
To assure a
low-level trip at 18 feet, the transmitter had to be calibrated
to a minimum of 19 feet, 0.745 inches.
The calibration procedure for these instruments sets the trip
point at an intake canal level of 19 feet.
In the worst case
(all errors maximized and in the low direction), the trip occurs
less than 1 inch below the 18 foot level. The one foot margin
of the calibration procedure, however, appears to* have been
added by the procedure writer as some general instrument error
margin and is not the result of a controlled set point
calculation or calibration program.
In the this case there was
margin
in the calibration which nearly accommodated all
potential errors.
Instrument error misapplication in design
basis calculations is discussed 'in paragraphs 4.A.1.a. and
4.A. l.b.
Other examples of non-safety equipment which, in the original
design, were relied upon to perform functions important to
safety include ESW diesel start batteries, discharge tunnel VP,
and anti-siphon VB on the CW pump discharge lines to the upper
intake canal.
The accuracy of these instruments is also not
being calculated or controlled. Except for the ESW diesel start
batteries, this other instrumentation is non-safety grade. The
diesel start batteries are further discussed in paragraph
4;A.2.d.
Demonstration of ESW Pump Rated Flow
ESW pumps are rated by the manufacturer for 15,000 gpm at a 45
foot total developed head.
The accident analyses (i.e., canal
profile calculations ME-179 and ME-180) assume one of the three
pumps operates at rated flow following a postulated LOCA, one
pump is inoperative for maintenance, and one pump single fails.
However, the ability of a pump to de 1 i ver 15,000 gpm under
accident conditions has not been .demonstrated.
The following
problems were identified:
e
e
8
(1)
The quarterly PT relies on visual obs~rvation of the ~ater
plume formed at the exit of the discharge piping above the
water in the upper intake canal relative to a pre.set
benchmark.
There
is ~o
installed flow
4ndication
instrumentation. The setting of the benchmark was based on
a calculation which was prepared to verify, a minimum flow
of approximately 12,000 gpm.
Successful completion of the
test will, at best, verify approximateJy 12,000 gpm.
( 2)
The operator has no i ndi cation that an ESW pump diesel
drive clutch is disengaged, other than an over speed trip
of the diesel.
In this case, should the operator first
attempt to start the ESW pumps near the e~d of on~ hour (as
re qui red by design cal cul at ions ME-179 and ME-180), there
may not be enough time to dispatch an operator to the ESW
pump house, resolve.the problem, and start a pump prior to
the end of the hour.
In calculations ME-179, ME-180 and ME-166, minimum canal upper
intake water level tomes within inches of the minimum required
levet (16 feet in the case of ME-179 and ME-180; 17 feet in the
case of ME-166) just before. the third RSHX is i so 1 ated at
approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the start of a postulated LOCA.
If
the running ESW pump does not achieve its rated flow, canal
level will drop below min1mum. * (NOTE:
Rated.ESW flow is 15,000
gpm in all cases; however, calcula.tion ME-166 considers ESW flow
to be the IWP alert l eve 1 qf 14,100 gpm rather than the
manufacturer rating of 15,000 gpm.)
The imp~ct of canal level
decreasing below minimum is that the SW flow to the RSHXs could
be decreased below the 6000 gpm used as a design input to the.
containment pressure -and temperature analysis, which could
affect the environmental qualification of equipment inside
containment.
As a result of the ESW pump capacity concern described above,
the licens~e tentatively initiated a program to have each pump
(one at a time) refurbished by the pump manufacturer. Once all
three pumps have been refurbished and reinstalled, the licensee
has committed to perform a 48-hour performance test, both to
demonstrate flow capability and also to resolve a number of
other outstanding questions relative to ESW pumps such as diesel
heat production and lube oil consumption. The test will be run
with temporary flow indication but permanent flow instruments
will ultimately be installed.
The refurbishment program, the
48-hour test, and subsequent periodic testing should resolve any
concerns as to
ESW flow capability.
pump capacity
misapplication in design basis calculations is. discussed in
paragraphs 4.A.l.a. and 4.A.1.b.
g.
HX Fouling
'*
. (*
9
(1)
Removal of 2SW-203C Valve
(*
o'"
On September 15, 1988, a maintenance crew removed t~e SW
2b3C and D valves.
The 203 and 204 valves *isolate the
One side of the 203 valves is exposed to SW
at all times.
When the valves were removed, the discs were
covered with silt and organic matter. Silt had accumulated
in approximately the lower seven inches of the valves.
Oysters, clams, barnacles, and seaweed covered the cfisc.
Clams were present near the disc seating surfaces,.
Clams
were up to one and one-half inches in size and still fixed
to the disc and body.
Oysters were up to two and one-ha 1 f
inches in size. Barnacles covered the disc surface and the
valve body .
Silt is present due to low flow in the vicinity of valve.
Flow in the CW header (only several feet from the SW line)
would provide oxygen and nutrients to the marine life, and
silting would result due to the lower velocities present in
the lines to the closed valves.
The silt and debris
accumulated in front of the 203 va 1 ves would be flushed
into the RSHXs when flow through the line is e,stablished .
(2). Examination of the CW Lines and Condenser Water Boxes
Because they share a common water supply, the condition of
the CW components would be" representative of SW water
components.
The access manways to the CW tunnel were open
during the first week of this inspection.
Presence of
seaweed, barnacles, oysters and clams were noted in the
manway.
Interviews with the workmen involved in cleaning
the CW tunne 1 indicated the seaweed was from one half to
one and one-ha 1 f inches thick throughout the tunne 1.
Observation of the manway confirmed the solid blanket of
seaweed present on the surface.
The condenser inlet isolation valves were removed the
second week of the inspection which allowed viewing the
condenser water box.
The tube sheet showed seaweed
covering virtually all the tube sheet area.
Additionally,
about 50 percent of the condenser tubes appear to be
obstructed by the seaweed inside the tubes.
( 3)
SW Programs
The James River provides brackish river water for Surry.
The water contains forms of life common to salt water and
some forms common in fresh water.
Various species of fish;
crabs, eels, barnacles, clams, and oysters were observed
during the inspection.
Sea grasses were also present in
quantity.
In addition, the water is.silty.
The upper
-
10
(1 ..
intake can a 1 has* most of the same aquatic 1 i fe present in
the river.
Although most adult animal life cannot easily
pass through the trave 1 i ng screens, *the 1 arvae in many
cases can.
Shel 1 fish 1 arvae and immature -grasses are
microscopic and pass easily through the screens.
The
fouling mechanisms found in the CW system confirm this.
Large masses of * sea grasses were present.
Barnacles
covered exposed va 1 ve surfaces in the SW piping.
Oysters
and clams were present in quantity 1n sizes many tfmes
larger than could have passed*through the screens. Silting
was present in the stagnant areas of the SW pipe.
With
water flow, all the nutrients required for ,growth. are
present for the spread of the organisms.
Surry has a hi story that indicates prob 1 ems caused by
fouling and salt water enhanced corrosion.
The condenser
boxes are cleaned regularly to insure good heat
transfer.
Problems have occurred with CCW and the control
room HVAC chi 11 ers.
Currently, Surry does not have a
testing program to monitor the heat transfer capability of
the safety-re 1 ated HXs.
Mon i tori rig for fouling is not
performed
on
a
regular. basis.
Minimum
operating
requirements for CCW and
heat removal
were
not
available at the time of the inspection.
Confirmation
could not be obtained that the heat removal listed in the
UFSAR for the HXs was actualJy available.
Preoperational
test data baselining HX performance could not be located.
There is a possibility it was not performed.
The CW system and condensers receive maintenance attention
- due to their impact on plant efficiencies.
Components
important to safety_ and operating in the same environment
are not currently monitored for design perfbrmance.
In view of substantial marine growth, biological fouling,
silt~* and other mechanisms for HX degradation observed in
both
CW and SW condensers, coolers, and piping, the
inspectors and the system engineer took measurements of CCW
and SW parameters that would enable an estimate of SW flow
to be obtained.
On September 9, 1988, SW flow to the CCW
HXs was estimated by a shell side to tube side heat
balance.
Inlet and outlet temperatures on both shell ~ide
and tube side were measured using a single hand-held
pyrometer.
Using control room flow indication for CCW flow
~hell side flows were estimated.
The tube sid~ (SW flow)
was determined by performing a .heat bal.ance setting the
shell side heat transferred equal to the tube side heat
transferred.
e
11
Multiple heat balances were performed with the results
ranging from 9,000 gpm to 13,000 gpm total SW flow to the
At the time the heat balances were performed, upper intake
canal level was at 25 feet, as measured by contra l room
instrumentation.
At this level, theoretical clean pipe
flow was calculated (Crane Technical
Paper
No.
410
analysis) to be approximately 40,000 gpm for all fouf HXs
with no VP in the discharge tunnel.
The data indicated
that the flow was only one-fourth of the expected value.
While the flow balance methodology is sound, gathering of
the data is imprecise and the results must be considered
approximate.
In
addition, it was
reported by site
personnel that the outlet valves of two of the four HXs
were throttled at the time the data was taken (one valve
one-half open and one valve one-third open).
Neither the
errors in the data taken nor the reported throttling would
account for the estimated reduction in flow.
During the third week of the inspection, the inspectors
examined a CCW HX that had been taken out of service. The
downstream water box showed heavy silting and a distinctive
high water mark was present which indicated that the upper
approximately eighteen inches of the tubes did not have
water flow, but were airbound.
Examination of the inlet
water box identified that the tube sheet was fully covered
by seaweed.
Tube blockage by mussels and clam shells was
a 1 so evident. Severa 1 fish and crabs were present in the
water box.
Barnacle growth was evident on the hatch cover.
Due to the heavy growth of seaweed covering the tube sheet,
a .determination of the presence of barnacles on the tube
sheet could not be made.
Interviews with plant personnel
indicated that condenser water boxes are cleaned weekly
during some parts of the year.
frequently.
The CCW HX fouling appeared heavy enough to
preclude full design flow and roughly confirm the flow
numbers arrived at using the heat balance.
In view of the reduction in flow and the observed CCW HX
and condenser water box fouling,
the
heat exchange
capability of other safety-related coolers in the SW system
which were not specifically reviewed is questionable.
These coolers are significant because they support proper
contra l room HVAC system operation and high-head safety
injection pump operation.
They are also susceptible to
biological fouling and flow degradation.
By design, these
HXs are required to be kept dry under normal conditions.
e
However, RSHXs have been discovered partially filled with
- ~ater, (see paragraph 4.8.8) in spite of procedures to keep
them dry (apparently due to leaking valves, valve testing,
etc.).
Unless an effective program is established to
maintain
dry, fouling and degradation of this
equipment will occur.
For safety-related HXs, the design basis heat transfer' rate
is established by the heat transfer rate used in the
accident analyses.
If the heat transfer capability is
degraded (e.g. fouling of heat transfer areas, tube
plugging, etc.) below the design basis rate of the
analyses, the HX is essentially inoperative with respect to
its safety function.
In the case of the HXs cited above,
the safety functions of concern are:
HEAT EXCHANGER
RS
Chiller Condenser
Charging Pump SW
ccw
SAFETY FUNCTION
Post-LOCA containment heat
removal (including long term core
The analysis
of concern is the post-accident
containment
pressure
and
temp.era tu re profi 1 e.
Control room cooling.* Control
room electronic equipment is not
qua 1 ifi ed* to operate in a harsh
environment
because of control
.room cooling.
'
Charging pump SW cools the
lubricating oil coolers.
These
coolers are needed post-accident
for the charging pump high head
injection mode ..
The CCW HXs are not safety related
because Surry is licensed to
hot-standby as its safe shutdown
condition.
However,
once
one
p 1 ant is coo 1 ed down and on the
system,
continuous
CCW is
required as
the
cooling
medium.
Hence, in a post-accident
scenario, if the unaffected unit*
is on
RHR,
CCW fl ow must be
continued.
e
13
The licensee is currently opening and cleaning the service
water side of the safety related HXs at Surry.
In
addition, the licensee is in the process of establishing a
monitoring program, with specific acceptance *criteria, in
order to open and clean HXs on a continuing basis such that
minimum flow will be assured (or in the case of the RSHXs,
to assure they will remain dry). This may resolve concerns
relative to HX performance.
HX fouling misapplication in
design basis calculations is discussed in paragraphs
4.A.l.a. and 4.A.l.b.
h.
Environmental Qualification of Equipment
Due to the inaccuracies of the design calculation noted in
paragraphs 4.A.1.a and 4.A.l.b. of this report,the SW flow to the
RSHXs has the potential to drop below the minimum required
(6000
gpm)
by the post-accident containment pressure and
temperature analysis.
The results of the analysis can not be
assured because of the change to a design input (RSHX capacity).
Since the environmental
qualification of safety related
electrical equipment and instrumentation inside containment
depends upon the containment pressure and temperature profile of
this analysis, qualification of some of this equipment may be
invalidated.
However, the licensee has demonstrated that at a
23-foot canal level, minimum SW flow to the RSHX will be
provided with the most limiting' single failure of safety
equipment and without reliance on non safety related equipment
(see paragraph 4.A.1.c).
Since plant TS will be revised to
require a minimum level of 23 feet for operations, the matter of
environmental equipment qualification with respect to this issue
is satisfactorily resolved.
Within this area, no violations or deviations were identified.
i.
Design Modification Process
Two weeks prior to the start of the SSFI the licensee conducted
a SW system design review and identified that the upper intake
canal low-level trip instrumentation was not safety grade and
could not withstand a single failure.
In view of this
discovery, the licensee (through standing orders and proposed
UFSAR changes) instituted the following changes:
One ESW pump was required to be started within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of
the start of a OBA, and
If RHR was being used by the non-affected unit, all three
ESW pumps were required to be operable (one pump for the
e
14
non-affected unit, one for the affected unit, and. one
single failed).
These changes may have to be modified based on* additional
calculations.
The inspector reviewed
EWR 88-008 which replaced the ESW
clutch/coupling adaptor assembly that connects the diesel output
shaft to the ESW pump with a shop fabricated assembly ana EWR 87-251 which modified eight primary containment penetration
collars in the SW system.
The inspectors had concerns on both
of these EWRs related to the adequacy of 10 CFR 50.59 reviews.
These concerns were resolved during discussions with the
licensee.
The 1 i censee' s procedure SUADM-LR-12, Safety Ana lysi s/10 CFR
50.59/10 CFR 72.35 Reviews, Dated February 26, 1988, has wording
that implies that changes to the facility that do not change PCT
by more than 20 degrees Fahrenheit do not require that a safety
evaluation be performed.
This procedure was in response to an
NRC inspector's review of the original accident analysis for the
OBA. In this method6logy, the licensee improperly selected 32.5
degrees Fahrenheit as opposed to the actual minimum inlet water
temperature
of
25
degrees
Fahrenheit
as
the
starting
temperature.
The licensee stated that this neither required a
safety evaluation nor a 10 CFR 50.59 determination.
This was
based upon the use of the 20 degree Fahrenheit margin used in 10
CFR 50 Appendix K.
This is a misapplication of the 10 CFR 50
Appendix K criterion.
Appendix K cannot be extended to allow
basic design calculation assumption inaccuracies or physical
changes to the facility that appear not to change PCT by more
than 20 degrees Fahrenheit without a documented basis for the
change.
Discussions with licensee management indicated that the
example identified by the inspector was not the intent of
SUADM-LR-12 and that it would be changed to prevent recurrence
of the condition.
No additional examples of this practice were
noted.
Therefore, until the 1 i censee changes SUADM-LR-12 and
evaluates the effects of the changes in assumptions on the OBA,
this is identified as .inspector followup item 280,281/88-32-14.
An inspection performed July 5-8, 1988, questioned the adequacy
of the 10 CFR 50.59 review performed prior to replacing the old
RSHXs with new ones.
URI 88-27-01, Potential Inadequate 10 CFR
50.59 Review for RSHX Replacement, was written to track the
concern until adequate information was available to resolve the
issue.
The new HXs design allowed greater flow through the HXs
than the old, for equal water head.
The new exchangers effect
on canal inventory had not been considered.
An adequate review
of this issue during the eva 1 uat ion phase of the exchanger
replacement
could
have
lead to self identification of
inconsistencies in the UFSAR accident analysis and design basis
j.
(*
k.
15
for the canal.
.Based on problems previously identified with
calculations ME-179, ME-180, and ME-166, this URI is considered
closed.
Preparation of Design Control Packages
General procedure STD-GN-0001, Instructions for DCP Preparation,
Revision 8, dated September 1, 1987, Section A.1.1.1 states that
preparation of a Design Control Package is mandatory when' the
design basis of existing equipment is changed or when
new
equipment is installed. Since calculation ME-180 (see paragraph
4.A.1.a) established the intake canal level at 27 feet, it
effectively changed the design basis of the intake canal. *
However, a design change package was not prepared.
Procedure NODS-ENG-07, Design Control Process, Revision 1, dated
5/5/88, Section 5.4 requires design verification for design
change packages.
However,. since a design control package was
not prepared, calculation ME-180 was not design verified.
A
design verification of this calculation may have revealed the
deficiencies in the assumptions and input to this calculation.
This is considered to be part of the overall design control
problem;
consequently, a. violation for failure to follow
procedure NODS-ENG-07 is not warranted.
Chiller Condenser Pump NPSH
In the past two years, 11 LERs have been written related to the
Control Room HVAC chiller condensers. This is further discussed
in paragraph 4.B.7.
While many of the LERs are related to
condenser fouling or tube plugging, others are related to pump
or condenser
switching problems
and therefore could be
indicative of pump cavitation.
However, the origi.nal design
calculation for NPSH available to the presently installed pumps
could not be located. Therefore, no conclusion can be drawn as
to the sufficiency of the NPSH.
Design Calculation 14937.53-M-l, establishes 12 feet (or less)
as the NPSH required for the new chiller condenser pumps.
This
calculation uses 18 feet as minimum upper intake canal level
rather than. 16 feet.
Sixteen feet is minimum level under
accident conditions to assure sufficient RSHX
flow
(see
paragraphs 4.A.l.a and 4.A.l.b).
On September 27, 1988, chiller condenser pump NPSH calculation
14937.53-M-l was revised to account for a 16-foot minimum canal
level, vice 18 feet.
In addition, a review of the NPSH was
performed for the existing pumps and it was determined that
sufficient NPSH was available.
16
"
o'
e
Within this area, no violations or deviations we~e identified.
1.
Protection Against Natural Phenomena
Section 2.3 of the UFSAR defines the maximum water levels for
the James River as the plant's design basis. These levels range
as high as 24 feet above MSL.
At higher river levels, the
static head of water available for gravity flow through th~ RS
The UFSAR assumes a reduction of the
upper intake can a 1 1 eve 1 to 26 *feet due tc;:> wind act ion during
hurricane
conditions.
At
a
24-foot
river
level,
the
differential pressure head is 2 feet of water. A static head of
2 feet is not s~fficie~t to deliver rated flow to SW HXs since
the
require an 8-foot <lifferential. Decreasing the
differential will seriously degrade heat transfer capability.
10 CFR 50 Appendix A Criterion 2 requires systems important
to safety be designed to with stand the effects of natura 1
. phenomena, including hurricanes and floods without loss of
capability to perform their design function.
It is not clear
how the Surry design meets GDC-2 with respect to the flooding _
assumed in the UFSAR.
This matter has been forwarded to NRR for
resolution and is identified as unresolved item 280,281/88-32-11.
m.
Maintenance arid Housekeeping Items
n.
During the course of the SSFI, traveling screens were observed
operating with sections of screens removed.
A 1 so, wh i 1 e the
inspection was in progress, the licensee identified foreign
objects inside system piping, including a wrench and a sump
pump.
The sump pump was identified by DR S2-88-456.
Loose foreign objects in the CW system may lodge in HX tube
sheet areas, in valves, or other fittings in the piping system,
possibly resulting in reduced flow and reduced heat exchange
capability for components important to safety such as the RSHXs.
Until the traveling screens are fully repaired and the licensee
identified objects in. the system are removed, this is combined
with additional examples and is identified as inspector followup
item 280,281/88-32-lS~a.
RSHX Replacement
The inspectors examined the new RSHXs prior to their transfer to
the protected area.
There were signs of rusting around the
bolting material on the HXs.
In addition, some weld fitup
blocks had not been removed at the factory, but were still tack
welded in place on some vessels. The blocks had been ground off
e
17
ori other vessels, but signs of gouging by the grinder were
present.
One of the. vessels in the yard was noted to have the
covers on the nozzles not sealed.
The covers were split .and
warped and the tape no longer provided a seal.
The
Joseph
Oat
Corporation Installation,
Operation and
Maintenance Manual for Recirculation Coolers, Revision 2A,
states .the followin~:
Units stored outdoors must have a desiccant maintenance
program.
Before being shipped, the nuts and bolts will. be
- coated with Tectyl 502C, a rust preventive. The integrity
of the coating, a waxy layer, should be checked every three
months and the nuts and bolts shall be recoated if
necessary.
The old coating need not be removed prior to
recoating unless rusting is evident, in which case the old
coating shall be removed with mineral spirits, kerosene or
other petroleum solvent and the rust removed with a wire
brush.
The coating need not be removed at the tinie of
installation.
The rusting was present, both on the bolts. and the flanges.
The
pre_serice of rust and the covers off, def eating any desiccant
program, indicate poor maintenance of the vessels while in
storage.
The failure to store this equipment prior to in.stallatio11 in
accordance with vendor recommendations and the licensees'
commitment to Generic Letter 83-28, which requires the licensee
to establish and implement programs for assuring that vendor
recommendations are included in site procedures, is identified
with additional examples as apparent deviation 280,281/88-32-09.d.
o.
System Walkdown
A walkdown was performed of selected accessible Unit 1 and
Unit 2 SW piping.
Equipment walked down is based on the follow-
ing flow drawings:
11448-FM-071A, Revision 24
11448-FM-0718, Revision 21, Sheet 1. of 2
11448-FM-071D, Revision 9, Sheet 1 of 1
11548-FM-71A, Revision 23, Sheet 1
11548-FM-718, Revision 22, Sheet 2
11448-FM-130A, Revision 8, Sheet 2 of 3
The following discrepancies were noted:
Drawing 11548-FM-07.lA (A-3 to C-3) does not reflect the
proper order of equipment and taps between the 205 valves
and the discharge.
As-built configuration is the
205
e
18
valve, bellows, RTD, FT, Radiation Monitor taps, and vent.
The drawing indicates the 205 valve, Bellows, one Radiation
monitor tap, vent, second Radiation monitor tap, FT,. and
RTD.
Drawing
11448-FM-071B does not reflect the as-built
configuration of PI23, PS2, PS1 and their connected piping
and valves (C-3).
PS1 is not off the same header as both
PI23 and PS2, but is located on a separate
11P.
Al°so,
1-SW-195 is shown branching off from the wrong side of the
111'
11 to 1SW119 (F-4).
FM-071B has the order of the tie in
from the Intermediate Seal Coolers Flow Indications to the
drain line in the improper order. The actual flow order is
101A, lOOA, lOOB, 101B, 101C, then to the drain line.
Drawing
11448-FM-O?lD
does
not
show
the
proper
configuration for the VS-PlA, B, and C leakoff seal and PI
connections.
Four valves, an eductor, and the associated
piping that canst i tute the 1 eak-off arrangement are not
shown.
In addition, the Pis on all three pumps will give
pressure readings that do not reflect pressure in the
pump's piping. The leakoff eductor flow will cause a lower
pressure reading due to the flow and associated pressure
drop in the instrument tubing. If the PI is to be used to
obtain accurate pressures, the flow must be stopped prior
to reading the gauge.
The pr.int is also missing the valve
numbers for the isolation valves for 1-SW-PIC-lOOA, B, and
C (E-7, E-5, G-3).
The print does not show.the bypass
valve and drain for 1-SW-DPI-108A (C-6).
Drawing 11548-FM-71B has some discrepancies in how it
depicts the Charging Pump SW pump's (2-SW-P-lOA) discharge
pressure instrumentation configuration.
Valve 2-SW-459
tees off prior to the common instrument header, not off the
header ( F-9).
The arrangement of the pump lOB pressure
instrumentation does not represent actual configuration.
The PI24 tees off the line followed by a cross servicing
SW3 and SW4.
Valve 2-SW-450 is capped at the end of the
line after the cross (F-8).
Drawing 11448-FM-071A does not sho~ the sight glass to the
v-ent trap and shaft bearing oil cooler for the ESW pumps.
In addition to the drawing discrepancies, the following items
were noted at the time of the walkdown.
Some items were noticed
to have been repaired before the end of the inspection.
Walkdown Items:
1-SW-255 - pipe cap is missing
p.
19
-2-SW-308 - pipe cap is missing
2-SW-349 - blind flange is missing
e
1-SW-PCV-lOOC - tag missing, excessive packing leak
l-SW-PI-116C - tag missing .
l-SW-PCV-1018 - heavily rusted, excessive packing leak
l-SW-PCV-1008 - heavily rusted, excessive packing leak
1-SW-320 - pipe not capped, Chicago fitting installed
l-SW-316 - tag missing
1-VS-P-lA - in spite of leakoff arrangement, leakoff fs
still present
1-VS-P-lA - there appears to be an orifice plate located
prior to PlA
1-VS-P-lA strainers - no numbers bn print~ not tagged
l-SW-DPI-28 - not tagged
1-0S-S-2A - not tagged or marked
1~os-S-2B - not tagged or marked
l-SW-108 - not tagged
l-SW-446 - not tagged
1-SW-448 - not tagged
l-SW-430 - not tagged
1-SW-450
pipe cap missing
1-SW-350 - blin~ flange not bolted
1-SW-346 - bolts very rusted
1-SW-301 - packing leak
l-SW-306 - packing leak
l~SW-302 - packing leak
2~SW-455 - tag missing
2-SW-459 - pipe cap missing
1-SW-268 - no tag
l~SW-26~ - handl~ missing
FI-SW-2008 - glass fouled, cannot read, acc~racy
questioned with fouling
FI-SW-201C - glass fouled, accuracy questtoned
FI-SW-200A - glass fouled, accuracy questioned
FI-SW-200C - glass fouled, accuracy questioned
1-SW-FE120B - T-shirt used as leak seal
1-SW-165 - tag missing
Most instruments were noticed to have been calibrated or
replaced within a week prior to the inspection.
Some parts of
the . system were found to be very rusty.
Rust was very
noticeable on control valves with excessive packing leaks.
Until the licensee evaluates these. items and updates drawings to
accurately reflect the as-built configurations, this is combined
with additional examples and is identified as inspector followup
item 280,281/88-32-15.b .
SW Pumphouse Walkdown
-
20
A wal kdown was conducted of the intake structure and its
associated buildings and components.
The structure is located
approximately 1.7 miles from the plant on the James River ..
The ESW pumps are located in a seismic structure behind the
traveling screens.
The pumphouse contains two diesel-driven ESW
pumps and one ESW pump that can be driven by either a diesel or
an electric motor powered from a non-emergency power source.
Each pump I s discharge line is a 24-i nch 1 i ne whose exit* is
located in the upper intake can a 1 at an e 1 evat ion of 33 feet
above MSL.
A go/no-go gauge (benchmark) is used to judge pump
flow and is located at the discharge line 1 s exit. There are no
discharge iso)ation valves or check valves located in the ESW
discharge lines.
The pump suction is located behind the
traveling screens, so the screens act to filter debris from the
river.
The ESW pump-s also have screens at their inlet to
prevent foreign matter from entering the pumps.
There is also a switchgear building which houses the electrical
equipment
to support operation of the CW system, and a VP
building, housing the VP system for the CW pump discharge
piping.
Observations made during the walkdown included:
Several of the CW water VBs ,were tagged to indicate they
were inoperable.
The intake traveling screens had sections missing which
could allow larger debris to reach the CW pumps and ESW
pumps.
Up to an inch of standing water was present in the ESW
pumphouse.
All instrumentation for ESW appeared to be calibrated
within a week of the inspection.
Pressure instrumentation for the ESW pump fl ow to the
diesel coolers was not bolted down, but was supported only
by the instrument tubing.
Diesel engine oil was present below the A and C diesels.
The angle gear cooling water flow sight glass was not shown
on the applicable drawing.
Until the licensee evaluates these items; this is combined with
additional examples and is identified as inspector followup item
280,281/88-32-15.c.
2.
. ('
a.
-
e
21
Electrical Design
The focus of the electrical design review was to verify that the
power sources which support various SW and RS system components
have adequate capacity and capability to supply the power
required for the systems to function as required by their design
bases, important ancillary support systems (such as HVAC) will
perform adequately to support the design bases operation of the
ESW equipment, and electrical control of the condenser isofation
valves was adequate. The inspectors reviewed selected clrawings,
equipment specifications, design calculations for the electrical
design,
specifications for mechanical systems equipment, and
design calculations for the ESW pumphouse HVAC systems.
The
inspectors performed walkdowns of the system to obtain data and
to observe the condition of the equipment .
Minimum Design ESW Pumphouse Ambient Temperature
The calculation for the minimum design ambient temperature
condition in the ESW pumphouse was requested.
No calculation
was provided; however, the licensee stated that the minimum
design ambient temperature was 55 degrees F, based on winter
conditions (10 degrees F outside air) with the ESW pumps
in-service.
On winter conditions with the ESW pumps not
in-service, the licensee stated that the pumphouse was normally
maintained at 70 degrees F.
The licensee advised that the basis
for the* 70 degrees F normal room temperature was the control
setpoint for the unit heaters in the pumphouse.
The licensee did not consider the effect on room temperature due
to a
and the resultant impact on
the
ESW diesel
operability.
On
LOOP conditions during winter, the electric
. unit heaters (which were previously operating) will de-energize
due to the loss of power and the room temperature will decrease
from
a starting
temperature
of
about
70
degrees
F.
Additionally, the licensee stated that the pumphouse air intake
and exhaust dampers fa i 1 open on* a* LOOP.
Therefore, any
residual heat available in the pumproom would be rapidly* lost
during adversely cold outside air temperature conditions. Prior
to this inspection, based on the calculated reserve capacity of
water in the upper intake canal, ESW pumps would not be required
to start for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after a LOCA/LOOP.
Low level in the
canal was used as the criteria to start the ESW pumps.
However,
the actual time after a LOOP or LOCA/LOOP when a canal low level
condition would occur had not been accurately established.
The
room ambient and the equipment temperature 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the
LOOP could easily be at the outside air temperature.
During
this inspection, Design Calculation ME-0188, Emergency Service
Water Pumphouse & Diesel Winter Cooldown Rate, Revision 0,
calculated that the room ambient temperature reaches the outside
. '
- -
e
22
air temperature, which is considered to be 10 degrees F minimum,
approximately 16 minutes after a LOOP.
The inspectors found on reviewing the equipment specification
for the ESW pump diesels, NUS-144, Specification for Screen Wash
and ESW Pumps, dated May 27, 1969, that the diesels were not
specified to operate or start for any minimum ambient tempera-
ture requirement. Also, the diesel battery_ specification data
sheet provided by the engine manufacturer specified the battery
performance at only 77 degrees F.
The diesel starting battery
was sized and supplied by the diesel engine manufacturer.*. As
such, the diesel battery may not be capable of starting the _
diesel for the minimum ambient temperature condition, since the
starting capability was not a specified design requirement.
Also, diesel lubricating oil would be adversely affected by cold
temperature, which causes additional design load on the starter
and the battery, and raises a question* on the adequacy of the
diesel lubrication.
After discussion with the di ese 1 engine manufacturer, the
licensee identified in a Surry Station DR, 1-88-0988, dated
September 29, 1988, that the operabi 1 ity of the ESW Pumps is
indeterminate since-it is questionable that the diesels could
start on design ambient temperatures of 10 degrees F, or for
diesel engine block temperatures lower than 45 degrees" F.
The
inspectors contacted the battery manufacturer and were informed
that the cold crank rating for tne Exide D~8D battery is 860
amperes at O degrees F for 30 seconds.
The licensee was advised
by the diesel manufacturer that the diesel requires 950 or 1250
amperes of cranking power depending if its_ temperature is
greater than or 1 ess than 32 degrees F.
Therefore, the abi 1 i ty
of the battery to provide sufficient cold cranking power has not
been established. In addition, the licensee was advised by the
diesel manufacturer that for diesel engine temperatures be]ow
45 degrees F, diesel starting aids are necessary to ensure
diesel* start-up.
Keep..-warm heaters, for example, would be*
required for the water/engine block and lubricating oil systems.
However, the inspectors noted that any starting aids would need
to be operable for a specified duration during a LOOP condition.
The failure to include appropriate design basis information
regarding the effects of minimum
ESW pump room operating
temperatures on diesel starting, diesel battery operation, and
diesel lubrication oil is contrary to 10 CFR 50 Appendix B,
Criterion III and the licensee
1s commitment to regulatory guide
1.64 and ANSI N45.2.ll.
This example is collectively combined
wfth additional examples and is identified as apparent violation
280,281/88-32-01.e .
b.
23
Maximum Design Ambient Temperature
o*
0
e
Ca 1 cul at ion 513N, Intake Structure Emergency Service Water
Diesels - Ventilation, Revision 0, considers two *ESW diesels
operating, with outside air at 93 degrees F, and determines a
maxi mum ambient temperature of 140 degrees F in the pump house.
However, all three ESW pumps may be operating. Therefore, the
inspectors identified that the maximum room amb1ent temperature
was not established, and more importantly, any adverse effect on
the performance of the diesels was not adequately evaluat~d.
Fbr example, the diesels were specified to operate in a maximum
ambient temperature of 100 degrees F as noted in NUS-144,
Specification for Screen Wash and Emergency Service Water Pumps.
Al though,
the licensee stated that temperatures above . 120
degrees Fare unrealistic, the original design basis calculation
(which con side red two pumps operating) calculated a maximum
temperature of 140 degrees F.
Therefore, inadequate design data
on the maximum ambient tem~erature conditions was used in the
original equip~ent specification for the diesel-driven ESW pumps.
The inspectors questioned the licensee on September 13",1988, to
determine whether any diesel derating is necessary for.pumphouse
arnbi ent temperatures above 100 degrees F.
In a telephone
- conference with the lic~nsee 1s engineers on September 20,1988,
the in specters expressed an additional concern that a* 140
degrees F (or higher) ambient tem'perature for the diesel could
result in a high temperature trip of the engine (which is an
automatic protective feature).
The high temperature trip could
potentially be common to all three diesels if they were all
operating simultaneously.
The diesel battery may also be
subject to failure in an abnormally high ambient temperature.
The licensee was requested to determine the
11 new
11 maximum
ambient temperature for the pumphouse and evaluate whether any
adverse operational or design conditions result.
The licensee
performed calculation ME-189, Revision O,*to establish the ESW
pumproom summer design indoor temperature.
One motor-driven and
two diesel engine driven pumps were considered to be operating
(worst case lineup from a heat load perspective) with 93 degrees
F outside air available for cooling.
The steady-state room
temperature for this condition was calculated to be approxi-
mately 185 degrees F.
The licensee contacted Detroit Diesel, the manufacturer of the
diesel engines, and was advised that a 1 HP decrease can be
expected for every 10 degrees F increase in temperature above 90
degrees F.
Therefore, a maximum derating of 10 HP due to the
combustion air temperature conditions in th~ pumphouse can be
expected.
The ESW pump maximum BHP requirement was reviewed by
the licensee to ensure that adequate HP was available from the
diesel driver for the maximum combustion air temperature
COflditions.
C *
e
24
The inspectors noted, however, that lead-acid batteries are
normally designed to operate at temperatures less than 120
degrees F.
If the battery is required for the continued
operation of the engine, or for essential features*which may be
required to stop the engine for an orderly shutdown or an
equipment protective function, the battery will need to operate
during the maximum design ambient temperature conditions.
The
adequacy of the diesel battery for a 185 degrees F ambient
~ondition is under review by the licensee.
'
The failure to include appropriate design basis information
regarding the effects of maximum
ESW pump room operating
temperatures on diesel operability and diesel battery operation
is contrary to 10 CFR 50 Appendix B, Criterion III and the
licensee 1 s commitment to regulatory guide 1.64 and
ANSI
N45.2.ll. This example is collectively combined with additional
examples
and
is . identified
as
apparent
violation
280,281/88-32-0l.f.
Adequacy of Class lE 125 Volt DC System Voltage
The inspectors requested design calculations for the s1z1ng of
cables and the voltage study or voltage drop analysis for the
newly installed Class lE 125 Volt DC System.
The licensee
stated that no formal design calc~lations existed on the sizing
of the Class lE 125 Volt DC system cables or on the voltage
drops in the system.
The licensee stated that system cables
were apparently sized based on an AE' s- design standard.
The
bases for the selection criteria for the cables was not fully
established.
The UFSAR, Section 8.2, states that the selection of cable
conductors is based on Power Cable Arnpacities published by the
IPCEA .
The inspectors concluded that the selection of cables
solely on the basis of ampacity considerations (conductor
temperature) will riot assure that adequate voltage is provided
at the equipment terminals.
In addition, as a battery ages and
looses capacity, its voltage performance likewise deteriorates.
Equipment operating outside its design voltage range is subject
to potential failure, especially the voltage sensitive loads on
the system, such as the Class lE UPS.
Inadequate voltage to UPS
equipment can cause maloperation, potentially resulting in UPS
equipment shutdown.
These systems generally include the plant
protection
systems
such
as reactor protection
systems,*
engineered safeguards detection and initiation systems,* and
essential
safety-related
instrumentation
systems
such
as
post-accident monitoring instrumentation systems .
For example, the station Class lE vital inverters or UPS were
specified in NUS-2061, Specification for Uninterruptible Power
d.
e
25
Supplies, Revision 1, dated November 27, 1985, to operate on a
DC input power supply voltage range of 105 volts to 140 volts
DC.
The licensee advised that the design criteria for voltage
drop/cable sizing was to maintain greater than 101 volts DC at
the main 125 volt DC distributi~n cabinets at the end of the
2-hour battery duty cycle. Also, the inspectors noted that the
minimum voltage available at the UPS is further decreased by an
estimated additional 1 percent to 2 percent drop in the feeder
cable from the main distribution cabinet to the UPS. Since" the
minimum voltage criteria for the main distribution cabinets
which feed the UPS equipment does not satisfy the UPS-specified
minimum voltage requirement, the inspectors could not establish
that adequate DC voltage will be available to power the UPS on a
design basis battery discharge, especially when the battery is
at an end-of-life condition.
Since no voltage drop or voltage profile analysis documents the
system design,
design modifications to
the
system were
apparently performed without a formal check to ensure that the
voltage was adequate.
For example, the Unit #2 Class lE station
batteries were being replaced during this inspection.
Similaf
batteries were already installed at Unit #1.
Class lE UPS
equipment was also added to the unit(s) recently.
Any inadequacies in the voltage available to operate equipment
would most likely go undetected in normal plant operation and
system surveillances because equipment is not normally being
challenged to operate at its rated design limits. For example,
the inspectors noted on a plant walkdown that the Class lE
system voltage at the battery is normally at the float charge
level, which is approximately 135 to 136 volts. This voltage is
the
11 normal
11
battery voltage when system surveillances are
performed.
Therefore, the ability of plant equipment to operate
when the minimum battery voltage exists (at the end of a design
discharge condition on the battery) is not confirmed by the
system surveillances:
Until the licensee fully evaluates the lack of voltage drop or
voltage profile analysis, this is identified as unresolved item
280,281/88-32-12.
ESW Pump Diesel Battery Procedures
The inspectors reviewed Weekly and Quarterly PT procedures for
the ESW pump diesel battery.
The acceptance criteria for the
surveillance testing performed on the ESW pump diesel battery*
does not ensure the capabi 1 ity of the battery to start the
diesel.
e
e
26
The
pump
diesel
battery is Exide type 0~80.
The
- manufacturer's rated specific gravity ror the type 0-8D battery
is 1.265 at 77 degrees F.
Likewise, at full charge and 77
degrees F, the battery voltage (6 cells) was calculated by the
inspectors to be 12.63 volts based on Exide recommended
procedures to calculate battery cell voltage.
Weekly Periodic Test, PT-23.7D, Emergency Service Water Pumps
Batteries Weekly Check, uses 12.4 volts as the acceptance
criter_ia for. an
individual battery (6 cells).
Two (2)
individual batteries are wired in series to form a baltery
assembly (12 cells total) for each dieseL
The acceptance
criteria for the battery assembly is 24.8 volts ( or twice 12 . .4
volts). The battery voltage acceptance criteria (at 77 degrees
F electrolyte temperature) is indicative* of a battery at
approximately a 75 percent state of charge, as noted in Special
Report No. 9, Station Battery Program Review, dated April 25,
1987.
On reviewing PT-23.7D, the inspectors also identified that there
were no acceptance criteria for electrolyte temperature and that
battery voltage is not compensated for temperature. Electrolyte
temperature is a necessary parameter to monitor to ascertain
overall battery environmental conditions.
An adversely low cell
electrolyte temperature would also be an indirect indication of
unit heater or unit heater control system malfunction.
Also,
battery voltage is not compensated for temperature.
At cell
e 1 ectro lyte temperature conditions 1 ess than 77 degrees F,
inaccurate indications of the adequacy of battery voltage could
exist and the* battery would be considered acceptable.
For
example, on electrolyte temperatures less than 77 degrees F the
battery voltage increases as* the battery specific gravity
increases.
As the battery voltage increases, battery float
charging decreases (since the charger produces a constant output
voltage), and effectively the battery can discharge as battery
capacity is consumed when surveillance testing is performed on
the diesel.
The licensee has indicated in Special Report No. 9, Station
Battery Program Review, that the basis * for the acceptance
criteria for the battery voltage was to ensure that the battery*
would not freeze (and su~tain damage)
on
adverse cold
temperature conditions in the ESW pumphouse.
The inspectors
identified that this basis is incomplete and incorrect in that
it alone will not ensure that the battery is capable of starting
the diesel in a partially discharged condition (75 percent
charged).
The inspectors also identified during the review of .Periodic
Test, PT-23.140, Emergency Diesel Service Water Pumps_ Battery
. ('
. e.
e
27
Replacement, that batteries being tested by this procedure may
also be inadequate for service since the instruction which
ensures adequate voltage also requires only 12.4 volts ,per
battery minimum.
This voltage,
as
previously *noted,
is
indicative of a battery which is only 75 percent charged.
The failure to provide adequate acceptance criteria in PT-23.7D
and
PT-23.14D
relating to acceptable battery voltage is
combined with add it i ona 1 ex amp 1 es of inadequate procedura 1
acceptance
criteria
and
constitutes
apparent
violation
280,281/88-32-03.a,b, and c.
Battery Specific Gravity Surveillance
The inspectors reviewed, PT-23.90, Emergency Diesel Service
Water Pump Batteries Quarterly Test, and i dent i fi ed that the
acceptance criteria for the specific gravity of the battery cell
electrolyte was 1.215.
Based on data in licensee's .Special
Report No. 9 the inspectors estimated that a specific gravity of
1.215 is representative of a battery in an approximate 70
percent state of charge ( or 30 percent discharged), si nee the
ful 1 charge specific gravity of the battery is 1. 265 at 77
degrees F.
The inspectors identified that the procedure did not correct the
specific gravity measurement for temperature.
The licensee has
indicated that pumproom unit heaters are thermostatically
controlled to maintain 70 degrees F.
Therefore, the battery
electrolyte temperature in winter is not maintained at 77
degrees F.
Furthermore, since the batteries are mounted near
the floor on an outside wall and the unit heaters are in the
overhead, the ce 11 e 1 ectro lyte temperature can be much 1 ower
than 70 degrees F due to temperature stratification in the room.
The
licensee indicated that the mini'mum
acceptance criteria without the need to correct for temperature
was the recommendation of the battery manufacturer.
However,
the
inspectors
could
not
independently
confirm
these
recommendations.
On discussion with the licensee 1 s engineer who
established the surveillance requirements, the recommendations
were made without any consideration given to the required
battery capacity to start the ESW diesel.
The failure to provide ftdequate acceptance criteria in PT-23.9D
relating to minimum specific gravity is collectively combined
with additional examples of inadequate procedural acceptance
criteria and constitutes apparent violation 280,281/88-32-03.d.
f.
Batteries Never Tested Without Charger
"
- ..
e
e
28
The inspectors reviewed survei 11 ance procedures for the ESW
pumps, PT-25.3A, B, and C, and identified that the batteries are
never load tested without the battery charger supplying part of
the starting current for the diesel.
However, the inspectors
calculated that the battery chargers supply less than one (1)
percent of the starting current requirement and that the effect
of the charger is minimal when the dies~l is started.
Regardl e*ss, the battery charger could easily be disconnected
from the station power supply during the ESW pump diesel
surveillance, and would thereby give a better indication of the
batter1 1s performance during the testing.
Until the licensee evaluates testing the batteries without the
- charger connected, this is identified as inspector followup item
280,281/88-32-16.
g.
Electrical Maintenance Procedure Minimum Specific Gravity
Electrical Maintenance Procedure EMP-C-EPDC-62, dated March 25,
1986, did not contain
adequate instructions for the minimum
specific
gravity
requirement.
Instruction
5.1
of
the
maintenance procedure required that the battery being installed
should have a specific gravity of 1.200. If not, the procedure
instruction required that the battery be placed on a charge to
bring the specific gravity up to minimum 1.200.
The inspectors
i dent ifi ed during discussions with. the battery manufacturer that
the batteries installed by the procedure, Exide D-80, have a
manufacturers rated specific gravity of 1.265 at 77 degrees F.
The inspectors estimated that the minimum specific gravity
requirement of 1.200 in the procedure allowed the batteries to
be commissioned for initial service at an approximate 55 percent
charged condition (or 45 percent discharged condition) at
77 degrees F, based on data provided by the battery manufacturer
to the licensee described in Special Report No. 9.
The acceptance criteria for minimum specific gravity to satisfy
the quarterly battery surveillance test, PT-23.90, is 1.215.
A
specific gravity of L 215 at 77 degrees F is equi va 1 ent to the
battery at an approximate 75 percent charged condition (or 25
percent discharged condition) as noted in Special Report No. 9
described above.
Regardless, the licensee, when advised of the
discrepancy between the EMP and the PT, initiated a Procedure
Change Request to procedure EMP-C-EPDC-62, dated September 26,
1988, which changed the minimum specific gravity from 1.200 to
1. 215.
The
failure to provide
adequate acceptance criteria in
EMC-C-EDPC-62
relating
to
m1n1mum
specific
gravity is
collectively combined with additional examples of inadequate
e
e
29
procedural
acceptance
criteria
and
constitutes
apparent
violation 280,281/88-32-03.e.
The inspectors also noted that Reference 2.2 in Electrical
Maintenance Procedure EMP-C-EPDC-62, which refers to the C&D
Battery manual, needs to be revised to include the Exide Battery
manual
and instructions relevant to the Exide 0-80 battery
covered by the procedure.
The 1 i censee stated that this
procedure would be updated.
h:
Seismic Design Qualification for ESW Pump Equipment
(1)
ESW Pump Diesel Battery Charger and Battery
The inspectors reviewed equipment specification for the ESW
pumps, NUS-144, and identified that specifications required
that the pumping equipment be designed to withstand a
seismic event.
The inspectors identified that this
specification requirement was not clear with regard to the
starting equipment for the E"SW pump diesels.
Therefore,
the
inspectors
requested
the. seismic
qualification
documentation for the ESW pump di ese 1 battery charger and
battery.
The
1 i censee,
after
a
search
for
the
qualification documentation, found that none was available.
The inspectors contacted Exide, the battery manufacturer,
and was advised that Exide had not seismically qualified
the battery.
Exide also stated that they do not plan to
seismically qualify the battery, since the battery, type
0-80, is manufactured and sold as a truck battery.
The inspectors also identified that the licensee considered
the
safety design classification of the battery as
non-Class lE. The inspectors were told that this was due
to the lack of any vendor seismic qualification for the
battery.
Therefore, the licensee's engineers considered
the battery as
11 non-Class lE (but crucial),
11 as noted in
Special Report No. 9.
Equipment is defined to be Class lE
as required by the function performed by the equipment.
As
defined by IEEE Standard 308 and endorsed by RG 1.32,
Criteria for Safety-Related Electric Power Systems for
Nuclear Power Plants, Class lE is the safety classification
of the electric equipment and systems that are essential to
containment and reactor heat remova 1 as we 11 * as other
essential
safety
functions.
The
treatment
of
safety-related equipment, which is essential to ensure the
ultimate heat sink of the station, as non-Class lE is a
significant concern to the inspectors.
e
30
C,
C
e
Furthe~more, the inspectors un~erstand that the ESW diesel
batteries and charger were relocated to_ their present
location, mounted on the wall, by a relatively re~ent
design modification.
Also, the batteries were replaced in
1987 on Work Requests 354517, 354518, and 354519.
These
work requests identified the batteries as Nuclear Safety:
YES, and Class lE: NO.
Again, the failure to identify the
lack of qualification documentation for these components
during* the modification or to recognize the approprhte
design classification during the battery replacement, and
to take appropriate corrective action, ~s a shortcoming of
the design control *process.
During the inspection, the
inspectors were advised by the licensee* that a diesel
battery was
subjected to a seismic test and passed
successfully.
The lack of seismic design and qualification for the
battery charger can result in the potential failure. of the
equipment on seismic events.
On failure of the charger,
the battery could be shorted, causing a discharge or
failure of the battery.
Failure of the battery directly
impacts the operability of the ESW pumps, since the battery
is required for starting the ESW pump diese.l.
For the
conditions stated, the failures postulated could be common
mode to all three ESW pump diesels.
The
inspectors
understa~d that the licensee is evaluating. adding a
qualified isolation device oetween the charger and the
battery, as we 11 as adding an alternator to* the di ese 1
engine.
(2)
ESW Pump Diesel Exhaust Piping
On walkdqwn of the ESW pumphouse on 9-12-88, the inspectors
noted that the
ESW pump diesel(s) exhaust piping was
supported to concrete ceiling structures which appeared to
be the equipment hatches for the room.
The inspectors
requested the* analysis which concluded that the diesel
exhaust is sei smi ca lly i nsta 11 ed.
The exhaust 1 i nes are
positioned directly above and adjacent to the diesel
engines and their failure on a seismic event could damage
diesel engine components such as the combustion air intake
as semb 1 i es.
The 1 i cen see acknowledged. on September 18,
1988, that no existing seismic analysis for the diesel
exhaust lines could be found and that these lines were also
i'nadvertently not included within the scope of the IE
Bulletin 79-14" reanalysis effort.
During the inspection,
the licensee performed a seismic analysis of the exhaust
1 i nes which demonstrated that the piping stresses were
within the stress allowable limits of the ASME B31.1 - 1967
code.
However, on verification of th~ nozzle loads with
e
31
the diesel engine manufacturer, the licensee has indicated
that the nozzle loads were not verified acceptable.
(3)
ESW Pump House Dampers and Actuators
The licensee reviewed procurement documents and*vendor data
for the dampers and actuators to determine the applicable
design basis information. The dampers are required to open
to supply both the cooling and the combustion air for the
ESW pump diesels.
The initial review by the licensee was
not successful in determining the safety status or seismic
design data for the dampers or actuators.
The licensee has initiated a Surry Power Station Deviation
Report No. 1-88-0998, dated September 29, 1988, which addressed
the seismic qualification requirements of the ESW pump diesel
battery, battery charger, and exhaust piping, in addition to
other concerns related to the operability of the ESW pumps.
These items have been identified by the licensee on a deviation
report; Until the licensee evaluates these issues and performs
corrective actions to close DR 1-88-0998, this is identified as
inspector followup item 280,281/88-32-29.
i.
Design Verification Calculation for Class lE Station Battery
Sizing
The inspectors reviewed battery sizing calculations for the
Class lE station batteries, Verification of Lead Storage Battery
Size for DC Vital Bus, Calculation No. 14937.16-E-2, Revision 2,
for the adequacy of the methodology and design criteria, data,
and design assumptions utilized.
The calculation was provided
to the inspectors as the applicable updated analysis for the
battery capacity requirement.
The inspectors compared the load
data considered in the calculation and the one-line diagram for
the Battery lB di stri but ion system, Drawing No. 11448-FE-lG,
Revision 13, with the plant distribution equipment which was
observed during a system walkdown.
The inspectors identified that the drawing for the Class lE
Battery Bus lB, Drawing No. 11448-FE-lG, did not agree with the
battery loads considered in the
11 verification
11 calculation, and
both the drawing and the calculation also disagreed in different
aspects with the actual plant configuration observed.
The
discrepancies observed are as follows:
(1)
Battery Bus 18
The calculation considered the deletion and addition of
various loads from system busses.
Deletion of the Air Side
32
0 .
. .
e
Seal Oil Backup Pump, *the Computer Inverter, the Vital Bus
Inverter, and addition of two 15 KVA UPSs were adjustments
to the load schedules included in
the calculation.
However, on an inspect{on of the di~tribution *system busses
by the inspectors, the Computer Inverter was found to be a
load on the bus, as well as an L&N 2020 Remote unit and a
feed to the MCB Rear Panel. The sum total of the loads not
considered in the calculation is over 120 amperes.
This
120 amperes is over 20 percent more than the first minute
load which was considered in the battery sizing calculation
and it would also be an additional continuous 1oad over the
entire battery 2-hour duty cycle.
The last two loads were
not only not considered in the calculation, but in the case
of the L&N 1 oad, it was a 1 so not shown on the one-1 i ne
diagram for the bus.
Based on the sizing criteria utilized
by the licensee in the sizing calculation, the inspector
calculated that in order to account for the additional
loads which the inspectors identified, a battery with 13
positive plates would be required.
The existing batteries,
Exide 2GN-23, have 11 positive plates.
The licensee stated that the computer load was not included
in the load calculation because it was and is expected to
- be
removed
from
the station battery..
However,
the
calculation does not represent the design, therefore, the
design verification which wa~ performed is inadequate. The
calculation was last updated in May 1986.
Therefore, for
the past two and one-half years the potential existed for
design or operational decisions, which would be based on
the battery sizing calculation, to be inaccurate, since the
actual battery load was not complete1y and accurately
established.
One-line diagram Drawing No. 11448-FE-IG, Revision 13, was
also found to show a feed to the Air Side Seal Oil Backup
Pump from Bus 18, however, this feed was apparently
previously deleted.
The licensee acknowledged that the
drawing should have been updated for this change and until
this specific drawing is updated, this is identified as
inspector followup item 280,28/88-32-17.
(2)
Battery Bus 2A
The inspectors identified that the battery load from the
480 volt switchgear busses, both Class IE and non-Class lE,
may be understated.
For example, the current (ampere)
requirements for the 480 vo 1 t circuit breaker spring
charging motor, for certain electrically operated circuit
breakers, appears to be neglected in the battery load and
therefore was not considered in sizing the battery.
The
'
{'
j.
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33
subject electrically operated circuit breakers, which can
receive trip commands during OBA conditions, have a breaker
mechanism closing spring charging motor with a rated
average current require,ment of approximately* 10 amperes.
The rated starting or inrush current for the spring
charging motor can be significantly higher, some 6 to 8
times the average rated value. The
load duration is *very
short, for example, less than two seconds.
But the loads
could occur simultaneously on a battery since the circuit
breakers which receive contra 1 power from the battery may
be tripped automatically.
When the subject breakers are
tripped, the closing spring charging motor is automatically
energized by a breaker position auxiliary switch.
For example, on reviewjng Battery Bus 2A, the inspectors
identified that circuit breakers for the Containment Air
Recirculation Fan (2-VS-F-lA, Bus 2H) and the Auxiliary
Building Exhaust Fan (1-VS-F-59, Bus 2B2) are tripped
automatically on an SI.
The SI condition could occur at
any time after a LOOP when the battery would be on
discharge.
Based on the circuit breaker manufacturer I s
pub 1 i shed data, the inspectors ca 1 cul ated 120 amperes
(minimum) total spring charging motor momentary load for
the subject circuit breakers.
The battery verification
calculation stated the load as only 3.9 amperes for both
Bus 2Cl and 2B2, and 6.5 amperes for 480 volt Emergency
Switchgear Bus 2H fqr a. total load of 10.4 amperes.
The
loads could occur as a first-minute load or as a random
load from a battery load profile perspective.
As a result of this inspection, the inspectors understand that
the verification calculation is under review by
licensee
engineers.
These examples of inadequate design control and
design verification of the Class lE 125 VDC station power system
battery sizing are considered to be
apparent violation
280,281/88-32-01.g.
Potential Loss of Combustion Air on Damper Single-Failure
The combustion air source for the ESW pump diesels is provided
by five e 1 ectri c-motor driven dampers at the ESW pump house.
Four dampers are located in the front wall and one damper is
located in the ceiling.
On hurricane conditions at the Surry
site, UFSAR Section 2.3.1.2.2 states that the air intake louvers
(dampers) located on the front wall will be made watertight by
means of a cover placed on the air intake duct structures inside
the pump house.
The UFSAR states that with the norma 1 air
intake louvers sealed, combustion air for operation of the
di ese 1 s would be provided by
11the motor-operated dampers"
located in the top of the pump house structure.
.*
e
34
C, * e
However, on inspection only one motor-operated damper was found
located in the ceiling and, as such, the damper is subject to a
postulated single failure.
For the conditions stated, a single
failure of the damper to open results in losing the combustion
air source for the di~sel drivers for the ESW,pumps.
Pending evaluation by the licensee, this is identified as an
unresolved item 280,281/88-32-13.
k.
Lack of Continuous Indication of Bypass of Engineered Safeguards
Actuation
On
reviewing Design Change No.
DC-88~17-3, the inspectors
identified that the design change incorporated a manual override
feature for the CLS open control circuitry for the RSHX
i~olation valves MOV-SW-104A, B, C, and D, and MOV-SW-lOSA, B,
C, and D.
The manual override feature is initiated by the
manual contr.ol switch for the valves and is accomplished by
simply operating the normal control switch for the valve to the
11close
11 position during a CLS Hi-Hi event, after the CLS signal
opens the valve.
Plant operators may elect to isolate a RSHX
post-accident to mitigate a leakage of radioactive material
which has occurred in the heat exchanger.
Isolation of the heat
exchanger is covered by plant procedures.
The inspectors identified that -t;.he
CLS open signal to the
isolation valves is a protective action of the engineered
safeguards as defined* by IEEE Standard 279, Criteria for
Protection Systems for Nuclear Power Generating Stations.
The
UFSAR, Section 7.2.1, Design Bases, states that the engineered
safeguards are designed in accordance with IEEE Standard 279,
August 1968.
Part 4.13 of the standard states that if the
protective action of some part of the system has been bypassed
or deliberately rendered inoperative for any purpose, this fact
shall
be continuously indicated in the control room.
In
discussions with licensee personnel, they were not aware of this
commitment.
Nevertheless, the inspectors identified that the design change
did not incorporate i ndi cation in the contro 1 room that a
protective action is bypassed.
Due to this variance between the
licensee 1 s commitments in the UFSAR, this is identified as
apparent deviation 280,281/88-32-10.
3.
Chemical Design
a.
SW System Inspection
The A CW piping which is the source of river water for the
SW system was inspected after marine growth, silt, and
b .
35
she 11 fish were removed by hydro 1 az i ng.
Severe through
wall corrosion was noted, particularly in the elbow leading
to the water box.
The corrosion mechanism was identified
as localized corrosion resulting in pitting:
Since the
pipe was coated, localized corrosion probably occurred at
discontinuities in the coating.
There was some evidence of
erosion possibly from silt and sea shells suspended in th~
cw.
The
inlet. to the condenser (96 inch, cast iron,
butterfly) valves were severely attacked by graphit i c
corrosion (leaching of iron in brackish water environment).
These butterfly valves are being replaced with ductile iron
units coated with an epoxy film.
Some valves in the SW
system were also attacked by graphitic corrosion and ~re
being refurbished or replaced.
were inspected to assess the performance of the epoxy
coaltar coating.
Some blistering of the coating was noted
with some clam growth as well as silting in some areas.
Prior to removing the A RSHX from containment, the SW
piping internals to the HX and the HX channel head were
inspected.
The SW system elbow to the HX was severely
corroded with large areas of heavy scale formation.
It
could not be determined whether the elbow was originally
coated.
The lower part of t~e SW piping was less severely
corroded with some blistering.
Epoxy coal tar coating
could be identified inside this piping.
The RSHX channel
head,
tube
sheet,
and
tubes
were
a 1 so
corroded.
Microbiologically induced corrosion was identified inside
the Cu/Ni tubes.
The SW side of the replacement heat
exchangers (channel
head,
tube sheet,
and tubes are
constructed of titanium Grade 2 material which is not
susceptible to river water corrosion).
The HXs shell side
are constructed of Type 304 stainless steel which is
compatible with the sump water during a OBA.
Galvanic corrosion tests were conducted to assess the
corrosion behavior of materials in contact with the
The corrosion rate of titanu.im to
stainless steel was very low while that of titanium to
carbon steel was high.
To
protect against potential
galvanic corrosion, the nozzle interfaces between the
carbon steel SW pipe connections and the RSHX titanium
channel head connections will be insulated.
Service Water Chemistry
A meeting was held with the Chemistry Supervisor to
determine
plant
chemistry
personnels 1
responsibility
related to the SW system.
River water is sampled and
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36
analyzed once per month.
The river water analysis is
basically for historical records.
Biofouling control
techniques; e.g., chlorination,. biocides, etc. are not
being employed.
The river water pH was revi~wed over the
period of the last two years and wis found to range between
7.5 and 8.0.
(1)
Biofouling, Corrosion, and Protective Coatings
Biofouling, corrosion, and protective coatings related
to the
SW system were discussed with the lead
mechanical
engineer
and
materials
engineering
personnel.
The CW system is constructed of 96-inch
diameter carbon steel piping inside the turbine
building and 96-inch diameter concrete tunnels from
the turbine building to the canal intake structure.
The 96-i nch
CW and 42- and 30-i nch SW piping are
presently coated with an epoxy coal tar coating. The
96-inch piping is being sandblasted, inspected, and
repaired followed by recoating with Chesterton No. 855
abrasion resistant cured epoxy (20 to 30 mils dry film
thickness). The water boxes of the condensers have a
3/16-inch neoprene rubber lining which performed well
in the river water environment. The tube sheet of the
titanium tubed condensers are coated with 30 to 35
mils of 100 percent sol ids epoxy.
The 4 RSHXs are
being replaced with titanium/stainless steel units
with a 0.0005 fouling factor on the sw* side.
The
Cu/Ni
tubes
of* the
original
experienced
microbiologically induced corrosion.
They were also
designed with a zero fouling factor on the tube side
since they were intended to be kept in dry lay up.
c.
Surveillance and Inspection Program
There is no formal
periodic program for
system
inspection in place at this time.
Some work was conducted
in the last several years and additional. activities will be
performed during at least the next two or three refueling
outages to inspect and repair the SW piping. Selected SW
system components have been or will be replaced including
the CW and SW valves, BC, CC, and RS HXs, and Mechanical
Equipment Room #3 chillers. The licensee plans to inspect
the refurbished SW system in the future.
The
following* documents
provide current information
NUREG/CR-4626, Improving the Reliability of Open Cycle
Water Systems, Volumes 1 and 2
4.
e
37
NUREG/CR-3054, Closeout of IE Bulletin 81-03: Flow
Blockage of Cooling Water to Safety System Components*
by Corbicula sp. (Asiatic. Clams) and Mytilus. sp.
(Mussel)
Configuration Control
The NRC inspectors field verified portions of the wiring
0 and
electrical wiring terminations in the RPS, SI system, and MCB
cabinets.
The majority of the identified discrepancies were in
the
MCB
cabinets.
Discrepancies
between
the
as-built
configuration and the drawings were identified.
The discrep~ncies identified by the inspectors included:
Capacitors installed but not shown on drawings.
Licensee
evaluation : Capacitors appear to have been installed for
correction of high frequency noise, however there was no
explanation available of the cause of the discrepancies.
Examples : Drawing 11448-FE-4A, terminal block A, terminals
1 and 3, and drawing 11448-FE-4B, terminal block 8,
terminals 1 and 3.
Field conductors are the opposite polarity of the polarity
indicated on the approved drawing.
Licensee evaluation :
none.
Examples : Drawing li448-FE-4A, terminal block C,
terminals 10 and 11, and terminal block F, terminals 1 and
2; drawing 11448-FE-48, terminal block 5, terminals 1 and
2; and drawing 11548-FE-4A, terminai block J, terminals 1
and 2.
Field cables are terminated on the internal side of the
terminal block and other field cables are terminated on the
external side of the terminal block.
These are not in
accordance with the approved drawings.
Licensee evaluation
- none.
Examples : Drawing 11448-FE-4A terminal biock G,
terminals 10, 11, and 12 and terminal block D, terminals
10, 11, and 12; drawing 11548-FE-4A, terminal block 1,
terminal 7; terminal block D, terminals 10, 11, and 12; and
terminal block 10, terminals 11 and 12.
Internal rack wiring is shown on the external field side of
the terminal block and is incorrectly identified on the
external *field drawing.
Licensee evaluation : none.
Example : Drawing 11448-FE-4A, terminal block H, terminals
5, 7, and 8.
External cables are terminated on the terminal block but
are not shown on drawings.
Licensee evaluation : none.
38
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c*
e
Example : Drawing 11448-FE-4A, terminal block 3, terminals
3 and 4 and terminal block 1, terminals 10 and 11; drawing
11548-FE-4A, terminal block 3, terminals 3 and 4, .and
terminal block 1, terminals 10 and 11.
-
External cables are terminated at the correct
a re shown on the drawing of the i nterna 1
Licensee evaluation :
none. Example drawing
terminal block 10, terminals 1, 2, 3, and 4.
terminals.but
side only.
11448-FE-4A,
Some 250 Ohm resistors are installed in the field but are
not on the appropriate drawings.
Licensee evaluation :*
none.
Example: Drawing 11448-FE-4A, terminal block 10,
terminals 8 and 9.
Installed instrumentation power supply is series jumpered
but is not shown on drawings.
Licensee evaluation : none.
Examples : Drawing 11448-FE-4A, terminal block 7, terminals
11 and 12, and all terminals on terminal blocks 8 and 9.
Drawing 11548-FE-4A, terminal bl~ck 7, terminals 11 and 12,
and all terminals ~n terminal blocks 8 and 9 .
Incorrectly labeled components on drawings.
Licensee
evaluation : typographical error.
Example : 11448-FE-4B,
terminal blotk C, terminal lf.
Color coding for installed wiring is not consistent within
cabinets.
Licensee evaluation : this does not represent a
concern and wi 11
not be changed.
Examp 1 es : drawing
11448-FE-4B, terminal block C, terminals 4 and 5; drawing
11548-FE-4A, terminal block D, terminals 7 and 8; and
drawing 11548-FE-4B, terminal block F, terminals 7 and 8
and terminal block H, terminals 1, 2, 7, and 8.
Several of the conductors of an RTD were rollsd.
Licensee
evaluation
none.
Examples
drawing
11448-FE-4B,
terminal block J terminals 8 and 9; and drawing 11548-FE-4B
terminal block J, terminals 1 through 10.
Conductors were shown terminated on drawings, but did not
exist in the field.
Licensee evaluation : none. Example :
drawing 11448-FE-4AS terminal A23-5.
The scope of this wiring review was not all inclusive and the
discrepancies listed above are not meant to represent all of the
wiring discrepancies in the cabinets examined.
Until the
licensee evaluates these discrepancies, this is identified as
inspector followup item 280,281/88-32-18.
I*
('
B .
5.
6.
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39
Health Physics
On
two
separate occasions the ins~ectors noted licen~ee
employees violating site health physics requireme~ts by exiting
through the radiation/contamination monitors at the exit portals
while the monitors were either inoperable or were alarming.
During the first observed incident, a licensee employee stood in
the exit portal monitor and after it alarmed he moved to the
second portal which also alarmed.
This employee and six Other
licensee employees passed through the alaiming exit po~tal and
left the protected area. The second observed incident involved
two licensee employees that used an exit portal that was marked
out-of-service and 1 eft the protected area.
This matter has*
been
referred
to appropriate Region
II Health
Physics
Specialists and.will be addressed in NRC Inspection Report Nos.
50-280,281/88-44.
Off-site Engineering
The inspectors contacted the off-site engineering staff both at
the site and at the Insbrook Technical Center.
The off-site
engineering staff appeared to be well organized, and records of
existing design calculations appeared to be adequate at the
Insbrook Center; however, some design records were difficult to
obtain on-site.
The inspectors reviewed numerous' existing design calculations
for the SW system prepared by the engineering staff at the
Insbrook Technical Center or by contractors.
Approximately 20
design calculations were reviewed at the Insbrook Technical*
Center and only one calculation had a questionable conclusion,
ME-079, Determination of the Corrosion Rate of the Component
Cooling Water HX 1-CC-E-lB Head.
The overall conclusion of this
design calculation indicated that there were
no
apparent
concerns with the CCW
1-CC-E-lB minimum allowable head
thickness.
The calculation failed to conclude that at the time
the calculation was performed, that the calculated corrosion
rate indicated that approximately 14 percent of the HX head
sample wai below minimum wall thickness and that after 18 months
approximately 50 perient of the HX head sample would be below
minimum wall thickness. This is considered an additional example
of inadequate design control and is combined with additional
examples
and . is
identified
as
apparent
violation
280,281/88-32-01.h.
OPERATIONS
The operation department 1 s involvement with the SW,
ESW, and RS
systems was assessed by directly observing operational activities,
system wal kdowns, personnel interviews, and document reviews.
The
--
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40
document reviews involved completed data packages, procedures, work
orders, LERs, DRs, EWRs, training lesson plans, system descriptions,
training records, shift logs, and the UFSAR.
1.
SNSOC Reviews of Procedure Deviations
TS 6.4.E requires that temporary changes to procedures receive
an approval from the SNSOC within 14 days of the change.
During
an inspection conducted in April 1988 (50-280, 281/88-11)', a
review of station DRs determined that between January 1987 and
March 1988 there had been approximately 60 DRs, each with an
average of three procedures, written on late SNSOC reviews of
tempera ry changes to procedures.
The
SN SOC identified this
problem in meeting 87-335, on December 18, 1987, but the action
taken between that time and the time of the inspection had not
resulted in an improvement.
This item was identified as a
weakness at that time because the licensee was in the process of
implementing changes that had the potential of correcting the
problem.
As a part of the corrective actions, the Maintenance Department
has instituted a work package control center which processes,
logs, tracks, and reviews all work packages.
As part of this
process, procedure deviations requiring review by the SNSOC are
identified,
logged,
and
assembled
for
the
department
superintendent to take to the SNSOC within seven days of the day
that the procedures were reviewed by the Operations Shift
Supervisor.
The program is new, being implemented in late August 1988. This
program has the potential for resolving the problem.
Within this area, no violations or deviations were identified.
2.
ESW Diesel Engine Fuel Oil System
The UFSAR states that the diesel engines, which power the ESW
pumps, have a fuel storage capacity sufficient to allow 125
hours of continuous operation. The inspector examined the fuel
oil storage tank operat i ona 1 requirements for verifying tank
level and determining fuel oil quality.
The fuel oil tank level is checked once per shift by the Outside
Watch Operator, in accordance with the Outside Log Sheet, which
provides the minimum and maximum levels allowed in the tank,
2500 and 4700 gallons, respectively. A notation existed on the
log sheet requiring the operator to notify the Shift Supervisor
of abnormal or out-of-specification readings.
e
41
. ("
c*
e
Periodic test l-PT-25.4 samples fuel oil on a monthly basis for
water and other impurities.
When the fuel oil tank level needed
to be increased, external connections existed for a tanker_truck
to allow additions to the tank. Adequate surveill~nces existed
to assure that the fuel oil system remains functional.
Within this area, no violations or deviations were identified.
3.
Operating Procedures for SW and ESW Systems
The inspector reviewed operating procedures for the ESW system.
These included Normal Operating Procedures, OP 49.2, Emergency
Service Water System,
and
Procedures,
l-PT-25.3A,B,C,
Emergency Service Water Pumps.
Requirements for ESW system
(diesel
engines
and
pumps)
operations were
compared to
instructions in the vendor manua1s for the Detroit Diesel
engines and the Bingham-Willamette pumps.
For non-emergency instances where the pumps are run, -the
procedures do not incorporate requirements from the vendor
manuals.
Some examples from the vendor manuals, which are not
incorporated, include diesel warm-up and cool-down prior to and
following
the engine
runs.*
In addition, there are no
verifications that oi1 pressure has increased during an engine
start nor are there checks for oil 1eaks during pump runs.
The
licensee stat~d that the warm-up and cool-down are not performed
because the PT is written to use a qui ck start as wou1 d be
required when the pumps are needed to provide the safety
function.
With a normal wear cyc1e of 7,000 to 10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />,
the reduction in the engine cycle hours due to running these
engines a total of 5 to 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> per year has been offset by the
assurance that the pump will quick start when needed.
This
appears acceptable for quick st'arting; however, other vendor
recommendations such as verifying 1 ubri cat i ng oi 1 pressure
increasing and checking for oil leaks are not included. The
failure to include vendor recommendations into appropriate
procedures is collectively combined with additional examples
and is identified as apparent deviation 280,281/88-32-09.c.
Section 2.3 of the UFSAR defines the maximum water levels for
the James River as the plant's Design Basis.
A review of
station procedures AP-37.01, Abnormal Environmental Conditions,
Revision
00.01;
EPIP-1.01,
Emergency
Manager
Controlling
Procedure, Revision 19; EPIP-1.03, Response to Alert, Revision
06; and EPIP-1.04, Response to Site Area Emergency, Revision 06,
was conducted to determine if the required actions during the
hurricane conditions are addressed. Utilizing these procedures,
emergency actions for preparation are taken; however, the loss
of CCW and/or RSHXs are not addressed and no instructions are
given to decrease the upper intake canal level to 26 feet MSL or
to m~ke the ESW building air intake louvers airtight, as stated
'
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42
in the UFSAR.
These procedures define the emergency cl ass
requirements, based on the intensity of the hurricane winds and
flood levels; orders the consideration of placing a uni"t in
shutdown, if necessary; establishes the required emergency
organization;
and
tak.es
certain
precautionary
measures.
However, the statements in the UFSAR as to the actions the
operators will tak.e are not reflected in the procedures.
Discussions with operations personnel,
from Control
Room
Operators up to and including the Superintendent of Operati~ns,
revealed that they were unaware of the statements that the UFSAR
mak.es regarding operations in this condition.
The absence of
the UFSAR commitments in the plant operating procedures is under
review by the licensee. This is further discussed in paragraph
4.B.6.
The inspector reviewed the operating procedures for the SW
system and verified the correctness of the va 1 ve
1 i ne-up
check.lists with the plant drawings and system walk.downs.
Even
though some discrepancies were noted in the drawings, there were
no
problems with the valve line-up checklists.
Drawing
discrepancies are discussed in Design Control section of this
report, paragraphs 4.A.l.o and 4.A.4.
4.
Use of Butterfly Valves in the SW System
The inlet and outlet isolation valves on the various HXs in the
SW and CW flow paths are butterflj valves.
These valves are
used in many cases to throttle flow thro~gh these *components.
The licensee has stated that using butterfly valves in
throttling applications where low fluid velocity, low fluid
pressure, and cold fluid service exist was acceptable.
The
licensee also stated that the use of the butterfly valves in all
applications in the SW system was acceptable- over the entire
range of valve travel due to the low flow, fluid temperature,
and fluid pressure which exists.
A record of a telephone conversation between a licensee
representative and a representative of the Henry Pratt Valve
Company on September 14, 1988, stated that in genera 1, Henry
Pratt does not recommend throttling valves below 20 degrees.
Throttling valves between 20 degrees and*90 degrees is not going
to affect the valve.
Below 20 degree the velocities may
substantially increase and cavitation may occur damaging the
seat integrity and subsequently the life of the valve.
However,
in this application (less than 4.5 feet per second) the
manufacturer's representative indicated that Virginia Power
should not have ariy problems even if the valves are throttled
below 20 degrees. This would; however, require confirmation by
analysis.
These general rules of operation apply to the
original butterfly valves as well as the proposed replacement
valves furnished by Henry Pratt.
"
,-
I
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43
While the CCW HX SW fluid velocity is below 4.5 feet per second,
and has been described in discussions with the manufacturer,
both the RSHX and the CW flow are above this value.
The manu-
facturer stated that analysis was needed to confirm the low
probability of cavitation at 4.5 feet per second.
Therefore,
it would also be required at the higher velocities experienced
in the other components.
Since the operators throttle these
valves based on required flow and not valve position, it" is
possible that these valves have been throttled at less than the
20 degree point, since there are no administrative controls to
prevent this.
Until the licensee evaluates throttling with
butterfly valves, this is identified as inspector followup item
280,281/88-32-19.
5.
Minimum Shift Crew Coverage
TS Table 6.1-1 requires a minimum shift operating crew to
consist of:
Shift Supervisor (SRO)
1
1
3
Auxiliary Operator (non-licensed)
4
Licensee procedure SUADM-0-07, Operations Department - Organiza-
tion, Responsibilities, and Functtons, approved August 23, 1988,
step 2.2.3 states that at any time a unit -is being Operated in
Power Operation, Startup, Hot Standby, or Hot Shutdown modes,
the minimum shift crew shall include two licensed SROs, one of
whom shall be designated as the Shift Supervisor, two licensed
ROs and two unlicensed POs for both units.
The inspector reviewed the balance of this procedure and
determined that even though this step in the procedure is les~
conservative than the TS
requirements,
the minimum staff
requirements described in other parts of the procedure met the
requirements of the TS.
The inspector reviewed the shift supervisor log for August and
September 1988 in order to determine that the minimum shift crew
requirements were met during that period. The following shifts
and- dates were times when the log did not accurately reflect
sufficient personnel to man both the minimum shift and the Fire
Brigade as required by TS:
Date
8/04/88
8/22/88
9/02/88
9/14/88
Shift
0800-1600
0800-1600
1600-2400
0000-0800
I
-
44
By reviewing time sheets and individual logs, the licensee and
the inspector were able to determine that adequate coverage was
present on site.
The fact that the Shift Supervisor was not
verifying and recording that the TS were met indicates poor log
keeping practices. Until the licensee assures correct logs are
being maintained, this is identified as inspector followup item
280,281/88-32-20.
6,
Operator Training for SW and ESW Systems
The operator training program for licensed and non-licensed
operators, in the area of SW system operations, was reviewed for
completeness arid accuracy against the system description and the
UFSAR contents.
R0.15.02A and R0.15.02B, for licensed operators, and
2.76.01 and 2.76.02, for non-licensed operators,
contain
instructions for the PTs on the ESW Pumps.
All four JPMs refer
to this test as a monthly test, however the test is actually
performed quarterly.
This is further discussed in paragraph
4.0.2.a.
In addition, the only measuring equipment referred to
by the JPMs is a vibration meter, for taking pump vibration
readings.
PTs l-PT-25.3 A, B, and C require that the pump speed
be recorded; however, there is no indication of pump speed and
operators have not been adequately trained to use a stroboscope
for this PT.
This is further discussed in paragraph 4.0.2.d.
System descriptions discuss
inlet isolation valves,
MOV-SW-104A/B/C/D, as being normally open.
These va 1 ves are
normally maintained closed and have been for several months.
The UFSAR, Section 2, assumes that certain actions will be taken
regarding the upper intake canal level in preparation for a
hurricane. These actions are not discussed in the training or
in the plant procedures.
These examples are not all inclusive
of discrepancies that exist between
the
system
descriptions, lesson plans, and the plant procedures.
Until
plant procedures accurately reflect the results of calculations
and UFSAR changes, this is identified as inspector followup item
280,281/88-32-21.
The inspector reviewed the qualifications records of selected
plant operation 1s personnel and determined that the records were
complete and up-to-date.
There was a completed checklist, or
test results for personne 1 exempted from sections due to
previous experience (e.g. Navy Nuclear Program graduates).
The
inspector did not identify any discrepancies related to the
training documentation for operation's personnel.
. ('
I
-
45
7.
Control Room/Relay Room Ventilation System Chiller Condenser
Problems
Since January 1987, the follciwing 11 LERs have be~n written on
various SW problems related to the main control room ventilation
chiller condensers: 87-002
87-007 88-007
87-003 87-008
88-020 87-005
87-018 88-025
87-006 87-021
The reportable events occurred whenever two trains of SW to the
control room ventilation system were simultaneously inoperable.
There were also cases where only a single train was inoperable
which is not ~equired to be reported.
Of the 11 LERs, 7 were
caused by inadequate SW fl ow to the chi 11 er condenser.
The
licensee identified cause of these seven occurrences was fouling
of various components by debris which included silts, seaweeds,
bivalve shells, and other assorted non-liquids.
LER 86-024, which occurred in August 1986, discussed replacing
the suction strainer for pump 1-VS-P-lB and replacing the
internals of the self-cleaning strainer.
EWR 88-347 was the
justification for reinstalling the pump suction strainers and
was completed after the inspection began on September 18,
1988.
The
EWR addressed reinstalling suction strainers as
remedial corrective action to resolve recurring problems:
The installation of these strainers and a prescribed
cleaning cycle has precluded plugging qf the chiller
condenser, manual throttle valve, and PCV valves.
LERs written since 1986; however, were not generally caused by
plugging of the chiller condenser, manual throttle valves, or
PCV valves, but by the plugging of the pump suction strainer
itself.
The
EWR stated that installing the pump suction
strainer would reduce the amount of cleaning required for the
chiller conden~er tubes for the following reasons:
Due to the screen mesh being significantly smaller than the
chiller condenser tube IDs, anything escaping the strainers
would have very limited impact on the chiller condenser
performance.
However, in the discussion section for EWR 88-347, the following
statement was made:
Annual cleaning of the chiller condensers is in progress*
but the plugging had reached an hourly rate during the
worst debris cycle in 1987.
,
-
46
Since the pump suction strainers were installed in 1986, it
appears that the pump suction strainer was not completely
reliable in preventing chiller condenser tube plugging.
The inspector examined portions of the SW system that had been
opened for maintenance and noted that evidence existed of the
growth of marine organisms on the piping and valve internals.
The assumption that the screen mesh will remove any debris large
enough to degrade the performance of the chiller condenser tubes
does not take into account the growth of organisms small enough
to pass through the strainer.
For example, the larvae stage of
most bivalves is microscopic and could easily pass through the
strainer mesh and would then grow large enough to plug the
chiller condenser tubes. Numerous bivalves were observed to be
growing in other portions of the SW system.
As part of installing the pump suction strainers, guidelines
were established for their periodic backwashing.
The pump
suction strainers were backwashed at least every two weeks or
anytime the pump discharge pressure dropped to 25 psig.
The
design pump discharge pressure was 43 psi (plus 2 psi static
head).
However, after the strainer had been cleaned, the pump
discharge pressure normally exceeded the 45 psig by 5 to 10 psi.
Thus, in some cases, the pump discharge pressure must drop by
approximately 30 psi before the pump suction strainer was
backwashed.
At this point, a substantial percentage of the
suction strainer would be plugged.*
The EWR also justified the suction strainer backwashing versus
the chiller condenser tube cleaning by stating that after the
suction strainer was backwashed, the pump discharge pressure was
normally 5 to 10 psi higher than design, indicating that the
chiller condenser tubes were not plugged, since the predicted
pressure drop for the chiller condenser had not been reached.
The pump discharge pressure indicators, 1-SW-PI-116A/B/C, are
between the pump and the chi 11 er condenser.
An increase in
indicated discharge pressure with the pressure indicator in this
configuration demonstrates an increased back-pressure from the
chiller condenser, indicating tube plugging, not the opposite.
The. actions taken to correct this problem that had been
previously identified by the licensee to the NRC and which had
resulted in
numerous
LERs
has not been adequate.
The
reinstallation of the temporary strainers had proven to be _an
ineffective resolution to the existing problem.
Problems have
continued to occur since that action was taken.
The written
justification and analysis for the actions taken was not
performed until it was requested by the inspector. When the EWR
was
issued,
it contained
inaccurate
and
contradictory
information.
This inadequate corrective action is part of a
more broadbased issue concerning the operability of the control
47
room/relay room ventilation system that is under NRC review.
Consequently, a finding will not be identified in this report.
8.
Water Found in the RSHXs
After cycling the SW supply valves 1-MOV-SW-103A & B for MOVATs
testing, on September 28, 1988, the operators assigned to drain
the SW piping between the valves and the RSHX inlet isolation
valves, 1-MOV-SW-104A/B/C/D, and verify that the RSHXs remained
free of water found greater than 20 feet of water in the A HX,
18 feet of water in the B HX, and greater than 20 feet of water
in the D HX.
On the following day, the MOVATs testing was
completed and greater than 20 feet of water was found in the C
HX.
Prior to the test start, water level was not checked in the
RSHXs, so it was not known if the water entered the HXs before
or during the testing.
The 104 valves were rebuilt during the
summer refueling outage and had successfully passed leak
testing.
The 104 valves had not been operated in the open
position during the present cycle, nor had they been stroke
tested since the outage.
Initially, the licensee attributed the problem to the 104 valves
leaking.
However, it was determined that without knowing the
status of the RSHXs prior to the test, the possibility that the
103 valves had been leaking existed.
The licensee's plans at
this point include the following:
a.
Developing tests to determine the source of inleakage
(which may require removing expansion joints to
visually inspect the valves while pressurized).
b.
Request engineering assistance.
c.
Blowing the RSHXs dry.
It is essential that these HXs remain dry while not in use,
since the heat transfer calculations used in the design of the
HXs assumes little (essentially zero) ,fouling.
Pending the outcome of the testing and the resolution of the
possibility of water inleakage to the RSHXs, this item is
identified as inspector followup item
280,281/88-32-22.
9.
SW and ESW Panel Configuration
The inspector performed a walk-down of the main control room SW
pane 1 s.
Modifi cat i ans have been performed on the Unit 1
instrumentation
panel
to
improve
the
groupings of the
indicators.
The Unit 2 panel has been scheduled for the same
,
48
"
C. -
modifications.
The ESW pumps indicate they are operating by a
red START light on the GETAC panel.
In case the pump trips, a
green STOP 1 i ght on the GET AC pane 1 is i 11 umi nated for that
pump.
Control room lighting appears adequate and does not hamper the
ease of reading the indicators and the recorders.
Noise levels
in the control room are minimized by the access controls
administered by the plant operation's personnel.
C
Within this area, no violations or deviations were identified.
C. .
Maintenance
During this inspection, an in-depth review of the maintenance program
for the safety related portions of the SW system was conducted.
The
inspection included observing work in progress and reviewing the
associated documentation for that work.
The inspection also included
a detailed review of completed work order packages including
applicable maintenance and calibration procedures, the vendor manual
for each component, and associated documentation for the completed
work.
Completed work order packages were selected based on the
importance of the component to plant safety and .to provide a
cross-sectional overview of all types of maintenance activities. All
work reviewed had been comp 1 eted in the past three yea rs.
The
primary focus of this review was to d~termine the technical adequacy
of the work performed.
The inspection also included reviewing
programs for predictive analysis, PM, trending, and root cause
analysis for component failures. Specific concerns are addressed in
the following paragraphs:
1.
Review of Maintenance in Progress and Complete Maintenance Work
Orders
As previously discussed, inspection sampling was designed to
provide a cross section of maintenance practices. Work reviewed
ranged from a simple gauge replacement to complete overhaul
or
replacement of MOVs and pumps.
The specific problem areas noted
during this portion of the inspection are discussed in the
following paragraphs:
a.
Work order 25253, Pressure Contra 1 Va 1 ve 01-SW-PCV-1008:
This work order and the associated maintenance procedures
accomplished a complete overhaul of the valve including
replacement of the valve body, bonnet, stem disc assembly,
etc. Problems noted:
Copies of the material control
parts were not included in the
the licensee was
unable to
traceability for these parts.
tags for installed
work order package and
establish material
,
49
C
0 *
The body to bonnet fasteners were over torqued to a
value of 590 ft-1 bs.
- The vendor manual did not
provide the torque value for these fasteners; ho~ever,
discussions between the licensee and
0 the vendor
determined the correct torque value to be 400 ft-lbs.
No proceduralized/documented post-maintenance testing
was
performed
on
the
valve
after
completing
maintenance.
b.
Work order 58398, Charging Pump Lubricating Oil Cooler SW
. Pump 02-SW-P-108.
The complete rotating assembly for this
pump was replaced.
The rotating assembly consists of the
shaft, the impeller, and the packing assembly.
Problems
noted:
Copies of the material control tags for the installed
rotating assembly were not included in the work order
package and the licensee was unable to establish
material traceability for this assembly.
The pump casing cap screws (Item# 370) and the gland
plate nuts (Item# 355) were over torqued to values of
83 ft-lbs and 18 ft-lbs,
respectively.
The vendor
manual
did
not
provide
these
va 1 ues.
Discussions between the licensee and the vendor
determined that the correct values are 50 ft-lbs and
10 ft-lbs, respectively.
c.
Work order. 29791 , Motor Operated Valve Ol-RS-MOV-155A.
This work order accomplished replacing the valve body to.
bonnet fasteners.
Problem noted:
The new fasteners were over torqued to a value of 150
ft-lbs. Conversations between the licensee and the
vendor determined the correct torque value as 120-135
ft-lbs.
d,
Work order 29790, Motor Operated Valve Ol-RS-MOV-1558.
This work order accomplished the replacement of the valve
body to bonnet fasteners.
Problem noted:
The new * fasteners were over torqued to a value of
150ft-lbs. Conversations between the licensee and the
vendor determined the correct torque value as 120-135
ft-lbs.
e.
Work order 45742, Gauge Ol-SW-PI-28.
This work order *
replaced the subject gauge.
Problems noied:
-~
e
e
50
No material control tags were filed in the work order
package. The licensee was able to establish material
traceability through the stock number which was
written
on
the work
order by
the ,.installing
maintenance technician.
This gauge was purchased as non-safety related and no
engineering
evaluation
of * this
condition
was
performed.
The purchase order for the gauge did not invoke 10 CFR
Part 21 on the vendor.
The gauge was calibrated by experienced maintenance
technicians and was considered minor maintenance.
No
records of the calibration were available.
f.
Work order 38044, Motor Operated Valve 10-SW-MOV-103C.
This work
included removing
of the motor,
bearing
replacement, and motor reinstallation.
Problems noted:
Paragraph
5.3.5
of
the
maintenance
procedure
( EMP-C-MOV-18) attached to the comp 1 eted work order
required data to be recorded concerning installed
jumpers.
This paragraph was signed off as complete
but data was not tecorded as required.
The full Joad amperage recorded in paragraph 6.10 of
the maintenance procedure (EMP-C-MOV-18) attached to
the work order was recorded as 3.2 amperes.
The full
load amper~s rec6~ded on ~he EQ data sheet was 4.8/2.4
amperes.
The
1 i censee was questioned
concerning
. which rating was correct. The licensee concluded that
2.4 amperes was the correct value.
This value
- indicated the actua 1 motor performance was out of
specification since the actual readings in the open
direction were 2.8 amperes ~nd the acceptance criteria
required amperage not to exceed 115 percent of full
load (115 percent X 2.4 = 2.76 amperes).
Note:
Current procedures require motor performance not to
exceed 125 percent of full load amperage.
This
problem
was .not discovered
during
work
performance nor during the comp l_eted work package
final QA review.
g.
Motor Operated Valve 01-SW-MOV-105C.
This work order removed the valve from the system, removed
the valve operator and reinstalled a new Valve and the old
operator in the system.
Problem noted:
'
('
h.
e
51
Paragraph 6.6 of* the completed maintenance procedur~
(EMP-C-MOV-11) which was attached to the work order
required
that current
readings on a 11* three motor
phases be taken and compared to the full load amperage
for the motor.
Readings were not to differ from the
f u 11 1 oad amperage
by more than + 15 percent.
A 11
six readings taken (0.6 amperes) exceeded the full
1 oad amperage ( 0. 95 amperes) by more than mi nus
0 15
percent and no corrective action was taken for the out
of specification
readings
nor
was
a procedure
deviation issued.
Work order 40304, Flow Transmitter 02-SW-FT-2058.
order accomplished replacement and calibration
Rosemount transmitter.
Problem noted:
The work
of a
The calibration procedure (CAL 466) used to calibrate
this transmitter did * not pro vi de the vendor manua 1
required closing torque value (90 in-lbs) for the
detector vent and drain va 1 ves used to vent the
detector during calibration.
i.
Work
order 56035,
Intermediate Seal
Heat
Exchanger
02-SW-E-lA.
This work order replaced the intermediate seal
HX and several sections of piping going to/from the HX.
j.
Problem noted:
C
Copies of the material control tags for the installed
HX were not filed in the work order package and the
licensee
was
unable
to
establish
material
traceability for the new HX.
Work
order
02-SW-E-lA:
HX and some
noted:
48151,
Intermediate Seal
Heat Exchanger
This work order replaced the intermediate seal
piping and fittings to/from the HX.
Problem
Copies of the material control tags for the installed
HX were not filed in the work. order package. The
licensee was able to establish material traceability
by reference to the purchase order on the work order.
k.
Work order 63350, Motor Operator Valve 01-SW-MOV-1038:
The
work on this valve consisted of removing the valve from the
system, replacing the valve seat, seat leak testing the
valve, and reinstalling the valve.
Problem noted:
Copies of the material control tags for the new valve
seat were not filed in the work order package.
The
e
52
licensee was able to establish material traceability
by reference of the purchase order and stock number
for the new seat on the work order.
1.
Work orders 26319, 26320, 26321, 47148, 47146, and 47144,
ESW pump batteries: The work orders replaced the ESW pump
batteries.
Problem noted:
.
A copy of one of the material control tags for the new
batteries i nsta 11 ed by work order 26321 was not filed
in the work 6rder package.
The licensee was able to
es tab 1 i sh rnateri a 1 traceability by reference to -the
stock number on the work order.
rn.
Work
orders 70085 and 70086,
Motor Operated Valves
02-SW-MOV-203C and 2030:
These work orders removed the
valves, replaced the valve seats, seat leak tested the
valves, and reinstalled the valves in the sys~em.
Problems
.noted:
The new va 1 ves seats were purchased from Jamesbury
Corporation. Jamesbury is on the Virginia Power
approved vendor list.
The only inspection ever
performed on the vendor was an eighteen criteria (10
CFR 50, Appendix B) surv,eillance, done in 1985 to add
Jamesbury to the approved vendors list.
The wrong post-maintenance test for stroke timing the
valve was referenced on the work order (PT 25.1 was
referenced in 1 i eu of the correct PT 25. 2).
This
error was corrected during this inspection.
There was no required post-maintenance test to verify
th~ leak tightness of the valve to the piping system
The
maintenance* procedure
(MMP-C-G-228)
used to
perform the work was weak since most of the procedure
was being deleted by procedure deviations.
Paragraph S.9.21 (Note) of the maintenance procedure
(MMP-C-G-228) requires a check of the disc to seat
clearance to ensure seat was making contact. However,
no acceptance criteria was provided for this check.
The following work order packages were reviewed and no
deficiencies were noted:
56579, 58821, 56565, 38112, 30391, and 30354.
"
e
53
To summarize the problems identified with the previous work
order packages, the system closure fastener~ on three valves and
one pump were over-torqued during m~intenance activities (work
orders 25253, 58398, 29791, and 29790). These deficiencies are
- the result of inadequate maintenance procedures and are collec-
tively identified as apparent violation 280,281/88-32-04.a,b,c,
and d.
.
.
-
.
Material traceability was not m*aintained for the replacement*
parts of a ~ressure control val~e, the rotating assembly of a
p~mp, and an installed HX (work orders 25253, 58398, and 56035),
These deficiencies are collectively identified as apparent
violation 280,281/88-32~0~.a,b, and c.
Post-maintenance *testing was not performed following a. major
repair to -an
SW system pressure contro 1 va 1 ve (work order
25253).
This
is
identified
as
apparent
violation
50-280,281/88-32-06.
-
Acteptance criteria was not incltided in MMP-C-G-228 (work orders
70085 and 70086).
This is identified- as apparent violation
50-280,281/88-32-03.f.
Vendor
requirements were not included in site procedures.
Specifically, torque values for vent valves on
Rosemount
transmitters were not included in calibration procedure CAL 466
This deficiency is identified as apparent
deviation 280,281/88-32-09.a.
A safety-related gauge was purchased as non~safety related and
installed without any engineering evaluation of this condition,
no 10 CFR part 21 was invoked, and no calibration records are
available to support the gauge calibration (work order-45742).
This is identified as inspector followup item 280,281/88-32-23.
2.
Preventive Maintenance
During this inspection, a review of the licensee PM program was
accomp 1 i shed.
This part of the inspection was conducted to
determine the extent of PM being actually performed on the
components in the SW and
CW systems.
The inspection was
accomplished by comparing vendor manual PM
requirements to site
PM procedures, reviewing adherence to 1 i censee and vendor
established PM intervals, and discussing the PM program with
licensee personnel.
-
54
The CW valves between the upper intake canal and the condenser
(Ol-CW-MOV-106 A, B, C, and D and 02- CW-MOV-206 A, B, C, and D)
for each unit and the CW valves between the condenser and the
outlet canal (Ol-CW-MOV-100 A, B, C, and D and 02-GW-MOV-200 A,
B, C, and D)
are not in the licensee 1 s routine mechanical PM
program;
however, these valves were replaced with new valves
during the 1988 outages.
No procedure has been developed to
accomplish PM on these valves.
Electrical PM is done, but is
often not done
on
schedule.
The valve operator vendo'r
(Limitorque) states that PM on the electrical and mechanical
portions of the valve operator should be accomplished on an
eighteen-month frequency until experience indicates otherwise.
These valves are required to close upon receipt of an accident
signal.
The vendor manual (Detroit Diesel) for the diesel-driven ESW
pumps includes the following preventive maintenance items which
have not been included in the sites PM procedure (SW-P-M/A3) for
the diesels:
The vendor manual requires a 20 minute wait after running
the diesel for a check of the oil level.
SW-P-M/A3 does
not include this requirement.
The vendor recommends treatment of the fuel oil for
preventing marine growth. The licensee 1 s procedures do not
address this recommendation.*
The vendor manual requires periodic cleaning of the diesel
cooling system using a radiator cleaning compound followed
by a reverse flush with fresh water.
Procedure SW-P-M/A3
does not include this requirement.
The vendor manual states that the starter motor wicks
should be oiled whenever the starter is removed or
disassembled for maintenance.
Licensee's investigation
indicates that this has not been done since as far back as
1981.
The vendor manual
crankcase pressure.
this requirement.
requires a peri cidi c check of the
Procedure SW-P-M/A3 does not 1nclude
The vendor manual re qui res a periodic cleaning of the air
box check valves followed by blow out of the lines.
Procedure SW-P~M/A3 does not include this requirement.
The vendor manual requires a periodic inspection and
cleaning of the blower screen.
Procedure SW-P-M/A3 does
not include this requirement.
. . *
./
'
-
55
The vendor manual re qui res a periodic check/change of the
lubrication in the reductiqn gear.
Procedure SW-P-M/A3
does not include this requirement.
Regarding MOVs, the electrical and mechanical PMs for MOVs which
must change position in an accident condition was not accom-
plished at the frequency_recommended by the vendor (Limitorque
-
18 months unless experience indicates
otherwise) or the
licensee 1s PM Program (annually).
Nearly all valves revi
0ewed
exceeded these PM frequencies. The following valves are listed
below to support the overall conclusion; however, this list is
not intended to be all inclusive:
Valve
01-SW-MOV-lOlA
Ol-SW-MOV-102A
01-SW-MOV-103A
01-SW-MOV-104D
01-SW-MOV-105D
Electrical
PM Dates
6/25/88
6/28/86
5/6/88
5/2/85
7/3/88
7/16/86
6/28/88
7/11/86
6/28/88
7/16/86
Mechanical PM Dates
8/26/87
No data provided
No data provided
8/26/87
No data provided
7/7 /88
7 /11/86
8/19/85
7/8/88
7/8/86
Vendor requirements were not included in site procedures related
to CW MOVs and ESW pumps and diesels.
These deficiencies are
identified as apparent deviation 280,281/88-32-09.b and 09.c.
3. Predictive Analysis
Revie~ of the licen~ee 1s _predictive analysis program for
safety-related portions of the SW and CW systems was also
conducted during this inspection.
The licensee primarily uses
three types of predictive analysis to anticipate component
failures.
Oil and vibration analysis are used to predict
failures in site rotating equipment.
These programs have been
in pl ace for a number of years and using these techniques
appears to be well integrated into the licensee's periodic
testing program.
MOVATS testing of motor operated valves is
also used by the licensee to predict failures. It appears that
this type of testing is more often used in determini~g the cause
, .
\\
-4.
o'=*
e
56
as opposed to predicting a failure. This technique has been in
use for over four years; however, .only a small percentage of the
critical SW and_CW valves have been tested by MOVATS.
There are
52 va 1 ves ( 26 per unit) that must *cycle during en accident
condition.
Of these 52 valves, only,10 have been MOVATS tested
and these 10 valves have only been tested on one occasion.
The
following is a listing of the 52 valves; valves which have been
tested are indicated by an*:
1-sw-Mov~io3 A*, B*, C*, D*
'l-SW-MOV-104 A, B, C, D
l-SW-MOV-105 A, B, C*, D
l-SW-MOV-106 A, B
l-SW-MOV-101 A, B
l-SW-MOV-102 A, B
l-CW-MOV-100 Al B, C, D
l-CW-MOV-106 A, B*, C, D
2-SW-MOV-203 A, 8, C, D
2-SW-MOV-204 A, B, C, D
2-SW-MOV-205 A, B*, C, 0*
2-SW-MOV-206 A, 8
2-SW-MOV-201 A, 8
2-SW-MOV-202 A, 8*
2-CW-MOV-200 A*, 8, C, D
2-CW-MOV-206 A, B, C, D
Until the licen~ee evaluates appropriate testing methods for all
CW and SW valves, this is identified as inspector followup item
280,281/88-32-24.
Trending and Root Cause Analysis of Component Failures
The licensee provided the inspector with a listing of the
maintenance hi story for a 11 SW components worked in the 1 ast
three years. Reviewing this list identified trends in component
failures.
The licensie was questioned concerning these apparent
trends. Discussing this area with licensee personnel determined
that the licensee does not have a viable component failure
trending and root cause analysis program in place.
ANSI
Nl8.7-1976 paragraph 5.2.7.1 requires that malfunctions of
safety related structures, systems, and components be evaluated,
recorded, and tr~nded.
Surry has not developed a comprehensive
evaluation*and trending program for corrective maintenance on
safety _ related equipment although this inadequacy has been
identified by various audit.activities. Findings in licensee QA
Audits S84-21, S86-09, and S88-21 have addressed this weakness.
- These findings encompass 4 years.
Reviewing corrective action
for Audit Finding S86-09-0l provided information as to the
status of . th.is programs deve 1 opment.
An audit task group
submitted recommendations to station management on August 27,
1987.
The recommendation proposed transferring responsibility
of failure evaluation and trending to Maintenance Engineering
from the Safety Engineering staff.
This proposal did not
address the format or mechanism for failure evaluation nor the
lack of guidelines for consistent evaluation performance.
This
proposal received four extensions awaiting management review
before action was taken May 5, 1988, tQ transfer responsibility
to Maintenance
Engineering.
An intermediate fix was to assign
..
., .
. (.'
D.
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57
one SES engineer this responsibility due to man power shortage
in Maintenance Engineering. Transferring responsibility did not
establish a program;
however,
in April
1988 the system
engineering concept was established and these system engineers
assumed responsibility for a tracking and trending program.
The
trending and tracking - failure analysis program was entered
into the station Commitment Tracking Program (Commitment No. 5)
and received periodic attention in 1987 but no resolution.
Procedure SUADM-LR-07, Failure Trending and Analysis of Safety
Related Equipment, dated May 17, 1988, and SUADM-ENG-08; System
Engineer Failure and Root Cause Analysis, dated August 15l 1988,
are
recent procedural
developments
which
represent the
licensee
1 s program development to date.
These procedures
provide minimal guidance on actual failure evaluations although,
if the
personnel
performing
the
evaluations
re.ceived
suppl ementa 1 training, the guidance would be sufficient.
A
licensee Audit S88-21 comment on electrical maintenance activity
also identified this problem.
Procedure SUADM-LR-07 requires
that the failure mechanism and failure mode be included in the
work performed section of the maintenance report, presumably
performed by the craft personnel.
Procedure SUADM-ENG-08
provided adequate guidance but the scope was limited to pressure
boundary failures of safety related and ASME coded systems and
components.
This procedure additionally states that documenting
failure and root cause analysis would be by the EWR process,
presumably performed by the system engineers.
Although review
of* system engineer failure evaluations indicated a thorough
evaluation of the subject failures, the program is inconsistent.
It would heavily burden system engineering resources if each
safety related equipment failure received on EWRs processed root
cause analysis.
In summary, after four years of identified need, a comprehensive
program for equipment failure evaluation and trending has not
been developed.
Lack of clearly defined responsibility,
guidance, and training for this function remains the basic
weakness.
Coordination of the numerous engineering groups
involved in plant activities aggravates developing a consistent
evaluation program.
Although this is a licensee identified
problem, corrective action has been inadequate to resolve the
issue.
This
is
identified
as
apparent
violation
280,281/88-32-07.
Surveillance
The inspectors reviewed survei 11 ance testing associated with the
safety-related
system.
This
included
reviewing
related
surveillance procedures, completed surveillances, and observing
surveillance tests conducted by operations personnel.
e
-58
1.
SW System Valve Testing
Safety-re 1 ated va 1 ves in the SW system are required by TS and
ASME Section XI to be tested every three months.
lhe testing is
performed per PT procedures PT-25.1, Quarterly Testing of CW and
SW System Valves, and PT-25.2, Testing of SW Valves to the
The valves are also tested each refueling outage to
verify proper operation on a CLS actuation signal. The valves*
are tested per PT-8.5A,
Consequence
Limiting Safeguards
Funct-ional Test Hi-Hi System.
The inspectors reviewed completed
copies of PT-25.1 and PT-25.2 for 1987 and 1988 to verify that
testing.was performed in accordance with applicable ASME Section
XI
requirements with regard to corrective actions and/or
increased test frequency when problems were identified during
quarterly valve testi~g.
While reviewing the Unit 1 SW system configuration, the
inspector
noted
the
inlet
isolation
valves
(Mov~sW-104A,B,C,D)
and
outlet
- isolation
valves
(MOV-SW-105A,B,C,D) are now being maintained closed instead of
open.
The valves are kept closed as part of the actions
implemented to keep the RSHXs dry.
The RSHXs were replaced
during the previous Unit 1 refueling outage and will be replaced*
during the current refueling outage for Unit 2.
A design change
had been implemented for Unit 1 adding logic so that the valves
now receive an automatic open signal. The valves were tested in
PT-8.5A to verify proper operatiori on a CLS signal. The desigM
change was being i!Jlplemented for Unit 2 during the current
refueling outage.
While reviewing the latest completed copy of _PT-25.1 dated July
7, 1988, the inspectors noted that valves MOV-SW-104A,8,C,D and
MOV-SW-105A,B,C,D were tested from the open to closed position.
ASME Section XI requires that valves be exercised to the
position required to fulfill their function and the full stroke_.
time measured.
The RSHXs inlet and outlet isolation valves are
required to be in the open position during a LOCA.
Thus, the
valves were required to have been tested and stroke time
measured fr6m their closed to open position.
The valves were
cycled from the closed to the open position in PT-8.5A, but the
stoke time was not measured.
The inspectors discussed this item
with licensee personnel who stated that the PT revisions were at
the final management approval stage.
The licensee further
stated that procedure deviation sheets were provided to the
Control Room to reflect the logi~ changes; however, the valves
were not ti med in the correct direction. - Failure to test the
valves in accordance with ASME Section XI requirements is
identified as apparent violation 280,281/88-32-02 .
2.
SW System Pump Testing
,_,,_
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59
The inspectors reviewed the Surry TS, UFSAR, and applicable
portions of ASME Section XI to determine te~t requirements for
the. SW system pumps~
The inspectors reviewed applicable test
requirements for the ESW pumps SW-P-lA,18,lC; chaPging pump SW
pumps
SW-P-lOA,108;
and
the control
room chiller pumps
VS-P-lA,18,lC.
While reviewing the test procedures for the
applicable pumps,
the inspectors identified the following
problems concerning whether testing met applicable requirem
0ents.
a.
UFSAR ESW Pump Testing Frequency
The UFSAR states that the ESW pumps will be tested monthly.
However,
the pumps
are being tested quarterly per
PT-25.3A,38,3C for ESW pumps SW-P-lA,18,lC.
The inspectors
asked licensee personnel why the pumps were not being
. tested in accordance with the frequency stated in the
Licensee personnel stated that the quarterly. test
frequency is in accordance with their Inservice Test
program
which
is consistent with
Section
XI
requirements. The licensee further stated that a deviation
report had been submitted* to ensure that the UFSAR is
revised to reflect the test frequency.
Until the UFSAR is
revised to reflect the correct test frequency for the ESW
pumps, this is identified as inspector followup item
280,281/88-32-25 ..
b.
ASME Section XI ESW Pump Testing Requirements
The inspectors reviewed completed copies of periodic tests
PT-25.3A,3B,3C for 1987 and 1988.
The tests were reviewed
to verify that the pumps were being tested in accordance
with applicable requirements.
The inspectors identified that the ESW pumps are not being
tested in accordance with ASME Section XI requirements in
that pump inlet pressure, differential pressure, and flow
rate are not measured during testing.
The inspectors
discussed this issue with li.censee personnel who stated
that they have submitted a request to NRR (Relief Request
11, Revision 3, dated March 27,. 1987) seeking relief from
measuring these parameters during pump testing because
there is no instrumentation installed to measure the
parameters.
The licensee stated in the relief request that
pump vibration and lubricant level are monitored during
testing which should be adequate indications of pump
performance.
The licensee also stated in the relief
request that a design change has been initiated for
discharge
pressure
and
fl ow
instrumentation.
The
inspectors questioned whether measuring only pump vibration
and lubricant level during testing provided adequate
information for determining whether the ESW pumps are
, ,.,
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1
C.
d.
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60
capable
of
performing
their design
function.
The
licensee's proposed IST program for the ten-year period
(1982-1992) has not been approved and is still being
reviewed by NRR.
A meeting was conducted on.March 29-30,
1988, between NRR and 1 i censee personne 1 to discuss the
proposed IST program.
Questions were raised by NRR during
this
meeting
concerning
when
and
what
specific
instrumentation would be installed to permit measuring ASME
Section XI re qui red parameters.
Licensee personne 1 stated
that as a result of the meeting with NRR, Relief Request 11
was being revised to identify a 1 tern ate testing where a
fl ow test was being performed by observing where the
discharge water impacts in the upper intake canal in
relation to a fixed reference point.
In addition to the
design change initiated for di..scharge pressure and flow
rate, inlet pressure will be calculated from river level.
Questioris concerning testing performed on the ESW pumps not
meeting the requirements of ASME Section -XI wi 11 not be
identified for followup in this report since NRR is aware
of the issue and he 1 d discussions with the 1 i censee in
order to resolve the previous questions .
ESW Pump Flow
The licensee has been determi,ning ESW pump flow during
testing by observing where the discharge water impacts in
the upper intake canal in re*lation to a fixed reference
point.
The reference point was positioned to- demonstrate
that each ESW pump delivers at least 12,000 gpm.
The PT
acceptance criteria and pump operability are based, in
pa rt, on whether the discharge fl ow from each ESW pump
touches the reference point during testing.
The inspectors reviewed the licensee's calculations for
positioning the reference point in the upper intake canal.
After reviewing the calculations and discussing them with
licensee personnel, and direct observation of PT-25.3C for
ESW pump SW-P-lC, it was determined that the actual flow
rate was 1 ess than 12,000 gpm ( about 11,000 gpm) even
though the pump discharge flow did impact the reference
point. This PT was performed on September 29, 1988.
The
TS state that the 1 ong term servi Ce water requirement for
the design basis accident is 15,000 gpm.
The UFSAR states
that the design capacity for each ESW pump is 15,000 gpm.
Thus, the licensee's PT contains
inadequate acceptance
criteria for demonstrating that the ESW pumps are operable
and capable of performing design functions as stated in the
TS.
This
item
is identified as apparent violation
280,281/88-32-03.g.
ESW pump Speed
,, **
3.
o'
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61
During the ESW pump testing. on September 29, 1988, the
inspectors observed that the value recorded for pump speed
was 440 RPM.
Th~ inspectors questioned this* value because
the pump is a single speed pump rated at 900 RPM.
Licensee
personne 1 stated that the va 1 ue was either read wrong
initially or.the wrong scale was used for the strobe light
which was being used to measure di ese 1 speed and pump
s~eed.
The inspectors nbserved the operator when the pump
speed was measured and the strobe light value was 440 ~PM.
Since the operator did not misread the value, and 440 RPM
was not* the correct pump speed, this indicates that the
test personne 1 had . no*t been trained in how to use the
strobe light properly.
The inspectors noted from reviewing
previously completed PTs that personnel had been recording
pump speed .as 1800 RPM.
This appeared to be the value for
the ESW pump_ diesel speed which i~ rated at 1800 RPM.
When
questioned concerning this matter,
licensee personnel
stated that the PT is confusing in this regard and will be
revised.
The PT performed on September 29, 1988, was
corrected with out being re performed to determine whether
the operator made a mistake when the test was performed.
The inspectors did not consider changing a value (which was
recorded during testing) subsequent to a test to be a good
practice.
The reason* for changing the value was not
documented in the comp 1 eted PT.
Unt i 1 personne 1 are
adequately trained in
performing this PT,
this is
identified as inspector follo'wup item 280,281/88-32-26.
e.
ESW Pump Tolerances
There are no tolerances given for the parameters such as
maximum or minimum values for pump oil levels, ESW pump
diesel oil pressure, and ESW pump diesel water temperature
in section five of the PT.
Although the parameters are not
part of the acceptance criteria, tolerances would give the
test personnel an indication if the ESW pump diesel
parameters are still within their acceptable ranges.
This
item was discussed with licensee personnel who stated that
consideration will be given to providing expected ranges of
certain parameters when the PT is revised.
Until the
licensee evaluates if tolerances are needed in the ESW pump
procedures.
This is identified as inspector followup item
280,281/88-32-27.
Control Room Chiller Pumps
The TS requires *that there be an operating SW flow path to and
from one operating control area ~ir conditioning condenser. It
also requires at least one operable SW flow path to and from at
least one operable control area control air conditioning
~ondenser. Both of these are required whenever fuel is loaded in
.r ..
I,,'
'
E.
QA/QC
e
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62
the reactor core.
In addition, the UFSAR states that the
required SW flow to the control room air conditioning condenser
is 330 gpm.
Service water is delivered to the control room air
conditioning condenser via the control
room chtller pumps
1-VS-P-lA,lB,lC.
The inspectors identified that there are no
surveillances to demonstrate that there is an operable SW flow
path to and from an operable control area air conditioning
condenser.
Additionally, there are no surveillances to test the
control room chiller pumps and the pumps are not included{~ the
licensee's
Section XI
inservice test program.
The
inspectors questioned why there are no surveillances to test the
chiller pumps and demonstrate an operable SW flow path to the
air conditioning condensers.
Licensee personnel stated that
chiller pumps are subject to surveillance via the Maintenance
Department's Maintenance Program.
The licensee further stated
that a PT is being developed to demonstrate operability of the
control room chiller pumps and thereby demonstrate the SW flow
path operability through the pumps.
The inspectors will review
the PT for adequacy during a subsequent inspection.
This is
identified as inspector followup item 280,281/88-32-28. -
Quality organization activities wer~ examined to determine
,
generally, the organization's ability to identify technical problems
and, specifically, to review QA/QC activities in the systems
encompassed by the SSFI.
The general review involved examining
previous licensee audits, audit schedules, scheduling responses to
evolving plant conditions, and audit finding corrective action
activity.
Examining_ this information provided an indication of
safety related QA activity scope, audit quality, and resolution
process
adequacy.
Additionally,
documentation
of
real
time
observation activity performed by QC inspectors was examined for
scope, depth, and resolution.
A specific examination of QA/QC
activity was performed on the SSFI systems under review to verify
that these safety related systems were subject to QA activity
consistent with that attention received by other plant safety-related
systems.
Reviewing the audit schedule and audit reports demonstrated the
licensee performed audits required by
6.13.
These audits
encompassed safety-related activities occurring on-site.
Followup
audits had been performed to verify effectiveness of corrective
actions for previous findings.
The
Quality
organization
has
demonstrated the flexibility to perform special unscheduled audits in
response to evolving conditions in specific plant areas. Examples
include audits performed of Independent Fuel Storage activities
(S87-25)
and station tag-out activities (S88-24).
The
audit
schedule, in conjunction with the flexibility to perform special
r ..
e
63
audits, provide adequate safety-re 1 ated activity coverage by the
audit group.
The qualify or technical merit of individual audits has improv~d in
the previous year and the recent audits identified more substantial
findings.
For example, PT audits over the last 4 years (S85-06,
S86-06, S87-06, and S88-06)
have demonstrated an evo 1 vi ng audit
qua 1 i ty.
The 1985 audit adequately verified comp 1 i ance with no
apparent technical depth; i.e., check list items regarding adequacy
of PT evaluations or test procedures.
The majority of check list
items* identified if an administrative procedure step was complied
with or the required individual signed for a review.
The 1986 audit
contained approximately 26 check list items; 5 of which represented
plant operability or safety impact issues. These items included the
following:
Do PTs on ESF equipment test equipment in condition required for
operation?
Are Unit 1 and Unit 2 procedures for same equi~ment equivalent?
Are PTs performed at required frequencies?
Does comparison of TS and PT index verify all TS requirements
are addressed?
Are department PT files up-to-date?
The remaining items and those of the 1985 audit provide little
insight into the functional success of the PT program.
The 1987
audit selected program requirements fo~ compliance with
six check
list items of merit, five were followup from the 1986 audit items
listed above.
One 1987 audit finding indicated that the auditors did
review the activity output; i.e., the PT for the outside RS pumps did
not eva 1 uate pump head as required by TS.
The 1988 PT audit
demonstrated a more direct review of the audited activity product as
opposed to a gross comp 1 i ance cross section review.
This audit
reviewed individual
PT results and analyses of these results
performed by plant personnel.
Audits of other plant activities;
i.e.,
In-service Inspection,
Design
Control,
Operations,
and
Maintenance, also were evolving towards reviewing the quality
activity end product.
Audit S87-07 of the In-Service Inspection
program utilized an NOE specialist which contributed to audit depth.
Utilization of technical specialists for plant audits was not a
common practice although it was evident that the the combination of
the audit group's exper:tise and specialist's greater depth of
technical knowledge produced a more comprehensive review of the
audited activity, thereby enhancing the quality organization's
capability to fulfill their function.
Design control audit S87-61 was a high manpower design activity
compliance type audit performed in late 1987 of North Anna, Surry,
and
corporate
design
groups.
Although
many
findings
were
administrative-compliance oriented, some findings demonstrated that
the engineering product qua 1 i ty was eva 1 uated to a greater degree
, ...
e
64
than previous audits.
The following items, applicable to Surry, were
identified from this audit:
Sample of EWRs identified examples of
Inadequate 10 CFR 50.59 safety analysis
Failure to review Design Base documents for safety analyses
Lack of independent review and review by design authority
Field change not subjected to design control measures
commensurate with original design change.
Inadequate controls to limit design change activity to the
designated design authority.
Inadequate disposition of Nonconformance Re~orts by the
Surry SEO
Inadequate/inconsistent processing of commercial quality
evaluations by the SEO related to commercial grade
procurement activity
These
findings
represent
another
example
of
the
quality
organization 1 s ability to identify problems.
The audits reviewed demonstrated an increased tendency to review the
activity output quality.
Previous compliance-based philosophy was
identified . as a weakness by the April 1988 QVFI ( NRC Report No.
50-280,281/88-11). The increased audit depth and findings* substance
evident in the previous year audit activity demonstrated the
capability of the audit organization to identify problems in safety
related activities.
Equal in importance to the scope and quality of audit activity is the
adequacy and timeliness of conditions adverse to quality resolution,
which has been identified as a weakness at Surry.
The QVFI
identified that audit findings were
closed without adequate
verification that the corrective actions accomplished were effective.
Additionally, plant responses to audit finding notifications were
frequently untimely.
In
response to closure inadequacies,
management now approves all closeout action.
In response to the
latter, a plant-wide memorandum was issued requiring prompt response
to AFRs.
Trending of response times by QA indicated improvement
since the memorandum was issued; however, due to the relatively short
time elapsed since initiation of these corrective actions, it was
indeterminate whether the finding resolution weakness is totally
resolved.
Real time quality organization inspection activity was accomplished
by the QC group.
This activity included observation of work in
progress, surveillances, and procedural holdpoint verification.
inspector comments and activities are documented in a QC inspection
1 og.
There is no requirement or guidance for 1 og entries nor
requirement that all activity be recorded in this log. Occasionally,
QC inspectors document comments on the work document.
Eight adverse
' .
65
0 *
e
findings or procedure deviations, noted {n the QC inspection log were
reviewed for documentation of the identified discrepant condition and
eventual resolution.
The following deviations or discrepancies were
listed in the inspection log by*job number and date:
Job 67316 dated June 9, 1988, Non-safety related gasket used in
a safety related application - RS system
Job 65335 dated May 13, 1988, Safety
related
air
valve
(PCV-MS-102B) failed valve operability test.
Job DC 88-01 dated June 21, 1988, Tack welds installed on RS
sump covers when procedure required seal welds.
Job DC 87-22 dated June 4, 1988, RSHX upper restraint gap less
than 1/16 inch minimum gap specified by drawing.
Job DC 87-22 dated June 21, 1988, RSHX installation procedure
require fit up per plant specification NUS-20, J-bevel
end
preparation.
Weld end preparation was
not
J-bevel.
Job 69526 dated August 11, 1988, Multiple findings on
replacement of SW radiation monitor pump.
Job 63352 dated May 19, 1988, Exc~ssive corrosion in RS system
piping.
Entry questioned the integrity of the pipe .
. Job 62913 dated May 1, 1988, QC holdpoint bypassed.
Although reviewing the deviations or discrepancies indicated that no
potential safety problems existed from those specific examples, they
represent a failure of the quality organization to adequately process
identified discrepant conditions.
In some cases, the corrective action *effectiveness was not apparent
although QC management indicated that the problem was resolved if the
QC signature was eventually entered on the work procedure.
The
existence of the signature was considered documentation of the
nonconformance or deviation resolution.
This signature provided no
description of how the identified deficiency was resolved nor was a
later QC Inspection log entry available to provide this information.
The licensee 1 s method of documenting QC inspection findings does not
provide a reliable process to ensure that identified discrepant
conditions are consistently and effectively resolved:
This failure
to adhere to ANSI Nl8.7-1976, paragraph 5.Z.l7, which requires that
inspection deviations, their cause, and corrective actions be
documented, is identified as apparent violation 50-280,281/88-32-08. *
In summary, the qua 1 ity organization possesses the resources to
identify problems in safety related activity in the plant. The scope
e
- 66
of audit and real time QC inspection activity included a cross
section of safety related systems encompassing the SSFI systems.
The
audit activity currently being performed demonstrated a depth
adequate to identify technical problems. although expanded use of
technical specialists would further enhance audit technical quality.
The organization has experienced weaknesses in resolving identified
problems from audit findings and QC inspections.
These weaknesses
have received management attention and are being resolved.
. ,, .
, ...
"
-
e
APPENDIX A
Licensee Employees
S. Alberico - Materials Engineering - Senior Engineer
J. Bailey - Superintendent of Operations
C. Baird - Site Engineering
L. Baker - Reactor Operator
- R. Benthall - Licensing
- R. Bilyeu - Licensing
M. Blankenship -
I&C Engineer
- H. Burruss - Licensing
R. Calder - Manager, Nuclear Licensing
- W. Cartwright - Vice President Nuclear
J. Clemmons - Senior Engineer
P. Conner -
I&C Engineer
8. Corbin - Atlantic Technical Services - Contract Engineer
A. Davis - Assistant to Chemistry Supervisor
C. Duong -
RS System Engineer
A. Farmer - Electrical System Engineer
8. Foster - Design Engineer
- E. Grecheck - Assistant Station Manager, Nuclear Safety and Licensing
R. Green - Site Engineering - Lead Mechanical Engineer
R. Green - Materials Engineering - Engineer
- N. Hardwick - Manager Nuclear Licensing
- R. Hardwick,Jr, - Manager Corporate QA
- D. Hart - QA Supervisor
8. Hill - Electrical Engineer
- H. Kansler - Station Manager
- J. Maciejewski -
SW System Engineer
E. May - Project Engineer
H. McCallum - Supervisor of Training, Power Station Operations
J. McCarthy - Operations Coordinator
S. McKay - Plant Engineering Supervisor
J. McGinnis - Senior I&C Technician
A. McNeill - IS! Supervisor
- G. Miller - Licensing Coordinator
- H. Miller - Assistant Station Manager, Operations and Maintenance
T. Miller - Electrical Engineer
- F. Moore - Vice President Powef Engineering Services
A. Price - QA Manager
R. Rasnic - Supervising Mechanical Engineer
T. Ringler - Assistant Shift Supervisor
P. Rippeth -
I&C Technician
E. Shore - Battery System Engineer
J. Smith - QC Supervisor
- D. Sommers - Licensing Supervisor torporate
- T. Sowers - Power Engineering Services
T. Swindell - Chemistry Supervisor
R. Stacy - Electrical Engineer
o*
e
Appendix A
2
S. Tajbakhsh - Mechanical Engineer
- G. Thompson - Maintenance Engineering
P. Tacker - Supervisor, Site Engineering Office
- J. Waddill - Power Engineering Services Mechanical
A. Wilson - Pipe Foreman
R. Wilson - Auxiliary Operator
S. Wiser - Mechanical Design Engineer
R. Zefar - Staff Engineer
Other
licensee employeis
contacted
included engineers,
operators,
technicians, maintenance personnel, and office personnel.
NRC Resident Inspectors
- W. Holland, Senior Resident Inspector
- L. Nicholson, Resident Inspector
NRC Personnel
- B. Buckley - NRR Project Manager
- F. Cantrell - Chief, DRP
- A. Gibson* - Division Director, DRS
- C. Haughney - NRR Chief, Special Inspection Branch
.*S. Patel - NRR Project Manager
- Attended Exit Interview
... * ..
...
I'
..
('
APPENDIX B
AC - Alternating Current
AE - Architect Engineer
AFR - Audit Finding Report
ANSI - American National Standards Instit~te
ASME - American Society of Mechanical Engineers
AP - Abnormal Operating Procedure
BC - Bearing Cooler
BHP - Brake Horse Power
CC - Component Cooling
CCW - Component Cooling Water
CFR - Code of Federal Regulation
CLS - Consequence Limiting Safeguards
Cu - Copper
CW - Circulating Water
OBA - Design Basis Accident
DC - Direct Current
DPI - Delta Pressure Indicator
DR - Deviation Report
EMP - Electrical Maintenance Procedure
ESF - Engineered Safety Features
ESW - Emergency Service Water
EWR - Engineering Work Request
F - Fahrenheit
FT - Flow Transmitter
GDC - General Design Criteria
GPM - Gallons Per Minute
HP - Horse Power
HVAC - Heating, Ventilation and Air Conditioning
HX - Heat Exchanger
I&C - Instrument and Control
ID - Inside Diameter
IE - Inspection and Enforcement
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IEEE - Institute of Electrical and Electronics Engineers
IFI - Inspector Followup Item
IPCEA - Insulated Power Cable Engineers Association
ISI - Inservice Inspection
KVA - Kilovolt-Ampere
L&N - Leeds and Northrup
LER - Licensee Event Report
LOCA - Loss of Coolant Accident
MCB - Main Control Board
MDV - Motor Operated Valve
MSL - Mean Sea Level
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Appendix B
NOE - Non Destructive Testing
Ni - Nickel
NPSH - Net Positive Suction Head
NRC - Nuclear Regulatory Commission
NRR - Nuclear Reactor Regulation
OP - Operatin~ Procedure
P - Pump
PCT - Peak Clad Temperature
PCV - Pressure Control Valve
pH *- Percent Hydroxide
PI - Pressure Indicator
PM - Preventive Maintenance
PO - Plant Operator
PS
Pressure Switch
PSI-- Pounds Per Square Inch
PSIG - Pounds Per Square Inch Gauge
PT - Periodic Test
QA - Quality Assurance
QC - Quality Control
2
QVFI - Quality Verification Functional Inspection
RG - Regulatory Guides
RO - Reactor Operator
RPM - Revolutions Per Minute
RPS - Reactor Protection System
RS - Recirculation Spray
RSHX - Recirculation Spray Heat Exchanger
RTD - Resistance Temperature Device
SEO - Site Engineering Organization
SER - Safety Evaluation Report
SI - Safety Injection
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SNSOC - Station Nuclear Safety and Operatirrg Committee
SRO - Senior Reactor Operator
SSFI - Safety System Functional Inspection
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TS - Technical Specification*
UFSAR - Updated Final Safety Analysis Report
UPS - Uninterruptible Power Supply
URI - Unresolved Item
VB - Vacuum Breaking
VDC - Volts Direct Current
VP - Vacuum Priming
VS - Ventilation System