ML20055D427
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| ML20055D427 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 06/27/1990 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20055D421 | List: |
| References | |
| 50-445-90-19, 50-446-90-19, NUDOCS 9007060292 | |
| Download: ML20055D427 (22) | |
See also: IR 05000445/1990019
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APPENDIX B
U. S. NUCLEAR REGULATORY COMMISSION
REGION IV
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NRC Inspection Report: 50-445/90-19
50-446/90-19
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Dockets: 50-445 Unit 1 Operating License: NPF-87
50-446 Unit 2 Construction Permit: CPPR-127
Expires: August 1, 1992
Licensee: TU Electric
Skyway Tower
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400 North Olive Street
Lock Box 81
Dallas, Texas 75201
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Facility Name: Comanche Peak Steam Electric Station (CPSES),
Units 1 and 2
Inspection At: Glen Rose, Texas
p, Inspection Conducted: May 3 through June 5, 1990 - r= Inspectors: S. D. Bitter, Resident Inspector, Unit 2
Project Section B, Division of Reactor Projects
_ j[ M. F. Runyan, Resident Inspector, Unit 2 mL Project Section B, Division of Reactor Projects ur ,,
R. M. Latta, Senior Resident Inspector, Unit 2
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Project Section B, Division of Reactor Projects
D. N. Graves, Resident Inspector, Unit 1
Project Section B, Division of Reactor Projects
A. T. Howell, Resident Inspector, Unit 1
Project Section B, Division of Reactor Projects
W. D. Johnson, Senior Resident Inspector, Unit 1
Project Section B, Division of Reactor Projects
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Approved by: .
D. D.6 Chamberlain, Chi &f Date
Project Section B, Division of Reactor Projects
Inspection Summary
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-Inspection Conducted: May 3 througa June 5, 1990 (Report 50-445/90-19
50-446/90-19) ,
Areas Inspected: Routine unannounced inspection of plant status,
operational safety verification, onsite followup of events, monthly
maintenance observation, monthly _ Surveillance observation, startup
test witnessing, followup of licensee event reports (LERs), followup
of previously identified items, followup of 10 CFR Part 50.55(e)
deficiencies, licensee plans for coping with strikes, and Unit 2
walkdowns.
Results: Within the areas inspected, two continuing areas of strength
were identified. First, a continuing high level of operations
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department personnel performance and professionalism was evident.
Examples of this include operator responses during two loss of
feedwater events that resulted in reactor trips (paragraph 4), as well
as operator performance during some of the more complex startup tests,
in particular, the turbine generator trip coincident with a loss of
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offsite power test (paragraph 7). Second, the conduct of the startup
test program is progressing well (paragraph 7),
, There were also two emerging areas of concern that were noted during
- this inspection period. First, some technical evaluations performed
in support of plant operations were performed after they were needed.
! One example is discussed in paragraph 3.d. Second, there have been L examples of noncompliance with Technical Specification surveillance ! requirements self-identified by the licensee. L L During the inspection, two violations and three inspector followup
items were identified.
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One' violation involved the failure to perform an isotopic analysis for
l iodine withutthe specified time interval (paragraph 7.c), while the . .other involved inadequate test procedure review criteria l (paragraph 7.d). The three inspector followup items included ! questions concerning problems with recent failures of the rod control l>
v system (paragraph.3.b), administrative controls of the Technical
E : Requirements Manual (paragraph 10.b), and a lack of procedural l' guidance to detail licensee processes for coping with strikes
(paragraph 11).
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DETAILS
1.- Persons Contacted
*M. Axelrad, Newman and Holtzinger
*J. L. Barker, Manager, Independent Safety Engineering Group
(ISEG) !
A. J. Bechem, Performance & Test Engineer
*J. W._ Beck, Vice President, Nuclear Engineering
*O. Bhatty,_ Issue Interface Coordinator
*M. R. Blevins, Manager of Nuclear Operations Support
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*A. R._ Buhl, Independent Advisory Group
*R. C. Byrd, Manager, Quality Control (QC)
*W. J. Cahill, Executive Vice President, Nuclear
*C. B.'Corbin, Licensing Engineer
*S. L. Ellis, Manager of Performance and Test
3 *J. L. French, Independent Advisory Group
*W. G. Guldemond, Manager of Site Licensing
ST. L. Heatherly, Licensing Compliance Engineer l
*C. B. Hogg, Chief Engineer j
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*T. A. Hope, Site Licensing .
*A. Husain, Director, Reactor Engineering
E. G. James, Supervisor, Balance of Plant (BOP) Systems, Design
Engineering
*J. J. Kelley, Plant Manager
*J. L. LaMarca, Manager of Electrical and I&C Engineering
*D. M. McAfee, Manager, Quality Assurance (QA)
*E. F. Ott.7ey, Project Manager, CASE
*H. S. Phillips, Consultant, CASE
*M. J. Riggs, Plant Evaluation Manager, Operations
*H. C. Schmidt, Director of Nuclear Services, General Division
*A. B. Scott, Vice President, Nuclear Operations
*J..C. Smith, Plant Operations Staff
P. B. Stevens,-Manager, Operations Support Engineering
*J. F. Streeter, Executive Assistant
*C, L. Terry, Director of Quality Assurance
*O. L. Thero, CASE
*T. G. Tyler, Director, Management Services
J. R. Waters, Site Licensing Engineer
l *D. A. West, Project Engineer L I. C. Whitt, Supervisor BOP Systems, Technical Support i
*Present at exit interview.
In addition to the above personnel, the inspectors held
discussions with various operations, engineering, technical
support, maintenance, and administrative members of the
licensee's staff.
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2. . Plant Status - Unit 1-(71707)
During most of this' inspection period, Unit 1 operated between
45 and 50-percent power in' order to perform'startup tests-
associated with the 50-percent plateau. On May 9, 1990, an
automatic reactor trip (paragraph 4.a) occurred on Lteam
generator low-low level because of a loss of main feedwater flow
that resulted during the calibration of the main feedwater pump
discharge pressure transmitter. Unit 1.was restarted on May 10,
1990, but-power had.to be reduced on May 13, 1990, in order to
repair the No. 2 main feedwater flow control valve which had
failed when its disc separated from-the valve stem. Testing at
the 50-percent plateau was resumed on May 15, 1990, until May 22,
1990, when the licensee conducted the turbine trip coincident ,
with a loss of offsite power test. Following a scheduled outage,
Unit-1 was restarted on May 26, 1990, but the licensee manually t
tripped the reactor-(paragraph 4.b) at 1:28 a.m. (CDT) on May 27,- '
1990, following the inadvertent closing of the No. 3 main
feedwater flow control valve. This valve failed shut as a result
of the failure of its train B trip solenoid valve. Unit 1 was
taken critical at 6:11 p.m. on May 27, 1990, and-power was
increased to approximately 49 percent by May 30, 1990. Unit 1
operated at or near 49 percent power for the remainder of the
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inspection period. ,
3. Operational Safety verification (71707, 71715)
l- The objectives of.this inspection were to ensure that this ! facility was being operated safely and in conformance with
regulatory requirements, to ensure that the licensee's management
controls were effectively discharging the licensee's
responsibilities for continued safe operation, to assure that
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selected activities of the licensee's radiological protection
! programs are implemented in conformance with plant policies and'
procedures and in compliance with regulatory requirements, and to
inspect the licensee's compliance with the approved physical
. security plan.
The inspectors conducted control room observations, including
periods of sustained around-the-clock control room coverage, and
L plant inspection tours and reviewed logs and licensee l' documentation of equipment problems. Through in-plant L' observations and attendance of the licensee's plan-of-the-day ' P
' meetings, the inspectors maintained cognizance over plant status
h and Technical Specifications (TS) action statements in effect.
The inspectors also attended licensee training lectures.
The inspectors performed a special inspection of the licensee's
methods for complying with pressurized water reactor moderator
dilution requirements. The results of this inspection as.well as
other inspector observations are documented below.
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a. . Temporary Instruction (TI) 2515/94, " Inspection for
. Verification of Licensee ChLnges Made to Comply with PWR
Moderator Dilution Requirements Multi-Plant Action
Item B-03."
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The inspector reviewed NUREG-0797, Supplements No. 23- -
and 24, " Safety Evaluation Report" (SER) related to the ,
operation'of Comanche Peak-Steam Electric Station, Units l'
and 2. Appendix C of SER, Supplement No.,24, documented the <
review of several boron dilution events and. concluded that
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the: calculated consequences of these transients were - ,
acceptable. Section 15.2.3.1 of SER, Supp.ement No. 23 1
noted that Amendment 74 to the Final Safety Analysis Report
(FSAR) was changed to reflect the plant as-built conditions',
e such as a dilution flow rate of 167 gal}ons per minute (gpm) L for all modes of operation and 4169 ft, minimum reactor .
coolant system volume for dilution during hot shutdown and '
c hot standby. The inspector reviewed Section 9.3.4 of the
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FSAR and noted that the FSAR did reflect the as-built- .
dilution flow rate and minimum reactor coolant volume that
was referenced in Appendix C of NUREG 0797, Supplement
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No. 23. The inspector also reviewed ~ Station Refueling
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Manual Procedure RFO-102A, Revision 3, " Refueling . .
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Operation,"-to verify that administrative controls cited in
Section 9.3.4 of the FSAR were in place to prevent
inadvertent boron dilution events during refueling !
, operations. Step 6.4.5 of RFO-102A satisfied the intent of '
-this' commitment. Temporary Instruction 2515/94 is
considered closed.
b. Troubleshooting and Repair of the Rod Control System
t During the course of plant tours, the inspector reviewed the
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actions taken by the licensee in correcting a loss of rod
! control system capability.
At 11:34 p.m. (CDT) on May 28, 1990, a rod control system
urgent failure alarm occurred on Rod Control Power-Cabinet :
IBD. At the time of the alarm, the rods were moving in
response to a dilution that had been-initiated to counter ~7
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xenon buildup. The control room personnel consulted the
alarm response procedure and ABN-712A, " Rod Control System'
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Malfunction." ABN-712A called for referring to several
TechnicalSpecificationsforpowerdistributgonandrod
insertion limits, adjusting Tavg to within 1 F of Tref by
using boration/ dilution or the turbine, and entering the
Limiting Condition for operation (LCO) for Technical
L Specification 3.1.3.1.c. The actions required by this LCO i called for_ ensuring rod alignment within i 12 steps
within 1 hour, and restoring the inoperable rods to operable
status within 48 hours. The required actions were completed .
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by the licensee.
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Troubleshooting by theLlicensee revealed that the signal
; : conditioning'and firing cards.were faulty. Using Work order'
(Wo) C90-3823, the licensee-replaced the cards. ;
, Subsequently, Procedure OPT-106, " Control' Rods Exercise," ;
was performed to verify' operability of the system. !
During'the followup of the licensee's troubleshooting and
repair activities, the inspector questioned the licensee's
methods foridetermining that unmovable control rods are
trippable when;there is no_ indication of a_ rod control
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i: system urgent' failure alarm. The inspector also noted that j
-this was the second time in two. months that rod control was :)
+ lost. Th'e inspector questioned whether these problems with
rod control may'be-caused by heat degradation. The
inspectors will monitor future operations of the rod control
system to determine-if these problems persist. These
inspections will be tracked by an inspector-followup item )
o (IFI-445/9019-01).
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c. Use of Feedwater Isolation Valve Hydraulic-Fluid
In response to an operational event which occurred at the
South Texas Project-(STP) Unit 1 on March 29, 1990, which
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involved the failure of the main feedwater isolation valves-
(FWIVs) to close completely.following a reactor trip,
.TU Electric initiated an evaluation of the FWIVs utilized at I
Comanche Peak. i
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As stated in the STP response to this event, the inability
of the FWIVs to close was directly attributable-to the
failure of the associated dump. valves to reposition which
would'have released the hydraulic fluid from the valve ,
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actuators. This was caused by the use of a specific type of
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hydraulicJfluid at temperatures above its manufacturer's
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recommended maximum steady state service conditions, coupled j
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with contamination which resulted in hydraulic fluid <
decomposition.
- Specifically, STP determined that the failure of the FWIVs
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to close within the required response time was caused by the 1
L blockage of the ports in the two pilot actuated solenoid {
dump valves attached to each valve actuator. The cause of
the blockage was attributed to the decomposition of the
hydraulic fluid (FYRQUEL EHC 150) due to thermal
degradation, accelerated by moisture and other containments.
As determined by the licensee, the FWIVs supplied to STP by
Paul Monroe are not utilized at CPSES. However, CPSES does
utilize hydraulically operated valves that are incorporated
in the FWIVs provided by Borg-Warner and on the Main Steam
Isolation Valves (MSIVs) which were supplied by Rockwell I
y International. A significant difference, however, is that l ':
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STP-utilized Fyrquel Type 150 hydraulic fluid whereas CPSES
m3 'does not1 utilize this type of-hydraulic fluid in the subject;
_ isolation valves. In accordance with_the respective
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, , manufacturer's recommendations, CPSES utilizes'Fyrquel
Type 220 MLT for the FWIVs and Fyrquel Type =220 for the
MSIVs.
As determined by the inspector, the CPSES applications of
Pyrquel' hydraulic fluids'for the FWIVs and-MSIVs appear to
be within an acceptable temperature range for their ,
application. Furthermore, both FWIVs and_MSIVs are
partially stroke tested quarterly and a sample of the
associated hydraulic fluid is independently analyzed as part j
of the periodic maintenance which-is performed on these !
valves. In addition, when in cold shutdown, which will
occur approximately every 18 months, these isolation valves
will be stroke tested. i
Based lon a review of the licensae's response to this issue
whichEincluded an evaluation of the periodic preventive
maintenance program for the subject components, and the use
of Fyrquel hydraulic fluid below the manufacturer's
recommended temperature application, it was determined that
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the licensee had adequately addressed this issue.
d. Use of Portable Hydraulic Lift Units on the FWIVs
During the previous inspection period, the licensee used 4
portable hydraulic lift units on-the FWIVs;to apply
additional forces in order to unseat the valves. During a
technical meeting between NRC and the licensee on May 9,
1990, the inspector questioned the acceptability of using
these portable hydraulic lift units on the FWIVs. Licensee
management personne1' indicated that a calculation '
(CS-CA-0000-2209) had been performed that demonstrated that
FWIVs and FWIV internals would not experience excessive
unseating forces as a result of using the portable hydraulic
lift units. The inspector noted, however, that this
calculation was not performed until after the hydraulic lift '
units had already been used. Even though the licensee
determined that the portable hydraulic lift units were
acceptable for continued use, the inspector was concerned
L that the affect of the hydraulic lift units was not known at
the time of their first use on the FWIVs. As a result of
this matter and previous questions about the adequacy of ,
licensee. technical evaluations, the NRC Fifty-Percent
Assessment Team Inspection will review this area. The
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results of the NRC team inspection will be documented in NRC
Inspection Report 50-445/90-20; 50-446/90-20.
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e. Leaking Motor Driven Auxiliary Feedwater Pump Oil Indicating ~i
Gage Gasket
During a review of the control room l logs,-the inspector i
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learned of difficulty that the licensee was experiencing in
maintaining-lubricating oil levelsLin the gage glasses on
w the inboard end of the motor-driven auxiliary-feedwater
(AFW) pumps. Subsequent investigation by the licensee
revealed:that the cork gaskets in the gage glasses were
becoming oil saturated, therefore the. oil is able to leak
through the gaskets. After discussing the problem with the
vendor, the licensee received (from the vendor) new rubber
gaskets that should solve the problem.
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Work requests were written for installation of the new
gaskets-in both No. 1 and No. 2 motor-driven'AFW pumps .'
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(WR 22422 and'WR 22423). The work is on hold pending an
evaluation by the engineering organization as to the ',
suitability of the new gaskets. Furthermore, the licensee
is determining whether the turbine-driven AFW pump has a-
similar problem. >
At no time'did this problem affect the operability of'the -
motor driven AFW pumps. The inspectors will continue to
monitor the licensee's progress in correcting the problem. ,
No violations or deviations were identified.
4. Onsite Event Followup (93702)
a.: Loss of Main Feedwater Flow and Automatic Reactor Trip on
Steam-Generator Low-Low Level
on May 9, 1990, at.3:05 p.m. (CDT), with Unit 1 operating at ;
approximately 48 percent power, a reactor trip occurred. '
The direct cause of-the trip was a low-low level in No. 4
steam generator. Indirectly, however, the trip was caused
by a loss of main feedwater pump (MFP) speed control.
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The licensee's investigation revealed that the loss of MFP '
speed control resulted from actions taken by I&C technicians
while calibrating the MFP discharge pressure transmitter. :
Specifically, the procedure used to calibrate the !
transmitter called for the plant to be in Mode 5 or 6. 1
However, a review performed by an I&C support engineer I
resulted in the determination that performing the
calibration with the plant in Mode 1 would be acceptable.
After receiving approval from the unit supervisor and
notifying the reactor operator, the technicians began the
calibration. l
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The second step of Procedure ICI-4247A, Revision 2,:" Channel- *
Calibration: Feedwater Pump Discharge Pressure and :
Feedwater Pump Speed Control, Channel 508," called for
installing jumpers across the = output' of the pump- speed ;
controllers.' When'this step was performed, both M?rs
coasted down because the jumpering caused a zero speed
U demand. Then, a feedwater isolation signal resulted~from
6 the excessively low feedwater flow and the feedwater
isolation ~ valves closed. Thus, insufficient feedwater flow
caused a low-low level in No. 4 steam generator which
resulted in a reactor trip.
Operator actions in response to this event were considered
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prompt and appropriate. Plant recovery was completed
E without complications. The NRC was notified via-the ,
Emergency Notification System in accordance with the t
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provisions of 10 CFR.50.72. A post-reactor protection
system actuation evaluation was-conducted in accordance with i
Operations Department Administrative Procedure ODA-108,
Revision 3, " Post RPS/ESF Actuation Evaluation." The
licensee is reviewing the adequacy of the I&C procedure
review process. Future inspection followup of the
licensee's corrective action will be' conducted after the
issuance of the licensee event report (LER) for this reactor
trip. -
b. Manual Reactor Trip Due to Lowering No. 3 Steam Generator
Water Level
on May 27, 1990, at 1:28 a.m. (CDT) with Unit 1 at :
44-percent power and a capacity test of the No. 4
atmospheric relief valve.in progress, the operating crew
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. initiated a manual reactor trip because of lowering No. 31SG
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water level, which had reached a level of 32 percent. The
cause of the loss of feedwater flow to the No.- 3 SG was the
failure of main feedwater (MFW) system flow control Valve
1-FCV-530. No other equipment problems were.noted following
the trip and the plant was stabilized in Mode 3.
L MFW flow control valve, 1-FCV-530, failed shut when its- !
train B trip solenoid valve deenergized, thereby venting
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opening air and causing 1-FCV-530 to-shut because of. spring
L force. The licensee examined the train B solenoid, which is ,
located outside, and found. evidence of moisture intrusion.
L The licensee suspected that moisture penetrated the train B
trip solenoid valve via its associated junction box and
cable conduit. The licensee inspected the seven other MFW
flow control valve trip solenoid valves and found no other
evidence of moisture intrusion. The train B trip solenoid ;
valve for 1-FCV-530 was replaced and the reactor was taken I
critical at 6:11 p.m. on May 27, 1990. The licensee is )
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evaluating methods to prevent further instances cf moisture
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intrusion into the MFW-flow control valve trip solenoid
valves.- Future. inspection followup of the licensee's
corrective action will be conducted after the issuance of
the LER for this manual reactor trip. ,
c. Auxiliary Feedwater System Check Valve Leakage
As previously reported in Inspection Report 50-445/90-13; ,
* 50-446/90-13, recent AFW system check valve leakage events q
have resulted in elevated AFW piping temperatures observed i
during plant operations. In an effort to enhance the.
operational characteristics of valve 1-AF-101, which is ,
a 4" Borg-Warner pressure seal swing check valve, located.on
the discharge line from the No. 2 motor-driven AFW pump to
the No.,4 SG, the subject valve was disassembled, inspected, ,
and reassembled in accordance with work order No. C90-3653.
The work activity was initiated to evaluate potential
seat / disc damage which was indicated in recent valve
radiographs and to lower the valve bonnet / disc assembly in .
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the valve in order to provide a more positive seating
surface. Subsequent to the reassembly of check
valve 1AF-101, both forward and reverse. flow tests were ,
performed in accordance with Procedures OPT-506A and '
EGT-328, respectively. Post-work test results and
radiographs indicated that the disc was lodged under the
seat ring in a manner similar to the conditions which
resulted in multiple failures of AFW check valves identified
during Unit 1 hot-functional testing in April and May of l
1989.
Accordingly, the licensee disassembled check valve 1AF-101
and inspected the valve internals. As determined by the
licensee, the root cause was attributed to a combination of
measurement errors and the unique relationship of the
contact point between the disc (with an unfinished edge) and
the seat ring. Following this determination, check
valve 1-AF-101 was reassembled in accordance with work order
No. C90-3699 using a new disc / stud assembly and a new swing
arm. The valve was then forward and reverse flow tested i
satisfactorily.
As a result of these activities, the licensee has
established that the previous margin which provided a
: nominal .050-inch excess to the retainer ring height
adjustment was adequate and that it should not be reduced
for valves with the older style discs.
No violations or deviations were identified.
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5.- . Monthly Maintenance observahion (62703)
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Station maintenance' activities for the safety-related and i
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nonsafety-related systems and components listed below were _
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observed to' ascertain that they were conducted in accordance with '
approved procedures,' regulatory guides, industry codes or
standards, and in conformance with the Technical Specifications.
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a._ Replacement of rolled pins with solid pins for stem / plug '
a assemblies-for the MFW system flow control valves (work
order Nos.,C90-3689, -3690, -3687, and -3691).
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b. Installation of resistors in the delta flux indicating
circuitryf(work order Nos. S90-417 through -420).
c. Troubleshooting and repair of rod control urgent failure
(work order No. C90-3823). A rod control urgent failure-
alarm was received on June 5, 1990. The indications at the
control rod drive cabinets were identical to the indications '
present following the rod control urgent failure alarm
received on May 28, 1990. Actions required by Technical
Specifications were implemented by the licensee upon receipt
of the alarm. Work Order C90-3823 was initiated tx)
troubleshoot the rod control system. The inspector obsnrved
a portion of the troubleshooting, which consisted primarily
of removing and reinserting a movable coil firing card, a
lift coil firing card, and-a signal processing card in power
cabinet IBD. Also, voltage readings were taken at various
test points in the 1BD power cabinet. During the ;
troubleshooting, the condition cleared and the urgent
failure alarm was reset. Further attempts to identify the
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malfunction were unsuccessful.
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All control rods were exercised to verify operability and
the Limiting Condition for Operation'was cleared. The work
order was-left open with an added sheet of test point
readings to take in_the' logic cabinet should the problem
reoccur. The inspector noted that this was the third
instance of a rod control system failure in two months.- As
indicated in paragraph 3.b, the reliability of the rod i
control system will be tracked by an inspector followup 1
item.
No violations or deviations were identified.
6. Monthly Surveillance observation (61726)
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The inspectors observed the surveillance testing of
safety-related systems and components listed below to verify that
the' activities were being performed in accordance with the
Technical Specifications. The applicable procedures were
reviewed for adequacy, test instrumentation was verified to be in
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'-' calibration, and test data was_ reviewed for accuracy and
completeness.. The inspectors ascertained that any deficiencies
identified were properly reviewed and resolved.
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The inspector witnessed portions of the following surveillance
test activities:
a. Emergency diesel generator air receiver. check valve
operability test (Procedure OPT-517A). -The inspector.noted:
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that the work procedure required the air dryer skid to be
depressurized by manually opening the relief valve at the
top-of the skid; however, the manual lift lever was missing. ,
from the relief valve. Also, the valve number for one check '-r
valve referenced in the work procedure was incorrect. The
maintenance technicians also_ identified these problems, and
initiated appropriate action to correct them.
b. Train A emergency diesel generator water-checks (Procedures .
SOP-609A and MSM-PO-3374),
c. Steam generator narrow range level analog channel
operational test (Procedure:INC-7335A).
d. Analog channel operational test and channel calibration
N16/Tavg, Loop 3, Protection VII Channel 0431B (Procedure
INC-7660A).
e. Containment pressure analog channel operational test
l (Procedure INC-7857A).
f. Alignment of neutron flux power range on current gain and
sum levc1 amp, Channels N41-N44 (Procedure INC-7401A).
No violations or deviations were identified,
7. Startup Test Witnessing (72300, 72302, 72583) :!
The inspectors witnessed selected startup tests in order to l
verify-conformance to testing commitments and procedural
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u i requirements, observe staff performance, and-to verify that
adequate test program records were maintained. The following
items were considered during test witnessing:
. Availability of current revision of test procedure.
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. Minimum crew requirements. t
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. Test prerequisites and initial conditions.
. Calibration status of test equipment.
. Technical adequacy of test Ic idure.
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. Test coordination and crew performance.
3 .- Preliminary results satisfactory or deviations
documented for further evaluation.
. Adherence to Technical = Specifications during testing.
v
In f.ddition, the inspectors reviewed various logs and reports and
attanded meetings and crew briefings related to the test program. ;
. ,
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DuJing this inspection period, the following startup tests were
ob served:
y a. NUC-203A, "Incore/Excore Detector Calibration."
The inspector witnessed the performance of a full core flux ,
map and a quarter core flux map in accordance with Procedure .
NUC-203, Revision 4,_"Incore/Excore Detector Calibration." [
The results of the flux maps were then used by the licensee !
to perform a preliminary calibration of the excore
instrumentation (NIS Power Range Channels N41', N42, N43,
and N44).- This calibration, which was performed at '
47.5 percent reactor power, will-be repeated at .
approximately 75 percent reactor power. The-inspector also
witnessed an informational secondary calorimetric performed
in accordance'with Procedure NUC-103, Revision 2,
" Calorimetric." A power level of 47.55 percent was. computed
for the calorimetric which compared closely with the four
NIS power range instruments, each of which read 47.5 percent .
power. No discrepancies were noted in the performance of
NUC-203 and NUC-103.
b. ISU-222A, " Turbine Generator Trip with Coincident Loss of
Offsite Power."
The: purpose of this test was to demonstrate the plant could
respond properly following a turbine / reactor trip with no-
offsite power available. This test was initiated from
approximately 18 percent reactor power, and the plant
responded as expected as evidenced by the transfer of unit
power to the standby diesel. generator power supplies and
stabilization of the plant in Mode 3. Three inspectors were- ,
in;the control room-during the test and evaluated operator
performance as excellent.
!
Following the reactor trip, pressurizer power operated
relief valve (PORV) PCV-455A actuated for approximately four
seconds. The lifting of PCV-455A was caused by the pressure
integrating feature of the control circuitry, rather than ,
'
the pressurizer pressure lift setpoint, which is set a
approximately 2335 psig. The licensee is evaluating the
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. acceptability of removing the pressure integrating function i
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of the control' circuitry.
c. >EGT-326A', " Steam Dump Valves Capacity Test."
q _The~ inspectors witnessed portions of the steam dump valve
capacity test. The licensee determined that the total a
capacity of all 12 steam dump valves +1s.approximately
53 percent. The original design capacity.for all 12 steam H
dump valves was approximately 40 percent. The licensee
,
evaluated the steam dump' overcapacity and found that the
overcapacity did not invalidate the applicable accident
analyses. As a result, the licensee determined that the
actual capacity of the steam dumps was acceptable and no
system modifications are required, j
one problem,:however, was noted during this test. On
May 20, 1990, during steam dump valve capacity testing, the
'
plant experienced power changes exceeding 15' percent of-
rated thermal power within a 1-hour. period. An isotopic i
analysis for iodine is required by Technical Specification
Table 4.4-1 between 2 and 6 hours following a thermal power
change exceeding 15 percent of rated thermal power.within.a-
1-hour period. This analysis was'not. performed within the
required time interval on May 20, 1990, because chemistry 1
technicians were not informed of the. power change. This was
identified by the licensee and documented in operations
Notification and Evaluation (ONE) Form FX 90-1603.
Additionally, there was'no procedural guidance in EGT-326A
requiring an isotopic iodine analysis following a thermal
power exceeding 15 percent of rated thermal power within
a 1-hour period. The inspector noted that the NRC
,
previously identified the same lack'of procedural guidance f
!
during an inspection conducted April 4 through May 2, 1990,
-following a review of Initial Startup Test Procedure
ISU-223A, " Remote; Shutdown Capability Test." This:NRC
review of ISU-223A is documented in NRC Inspection Report '
50-445/90-13;L50-446/90-13. The inspector noted that timely
, and effective corrective action taken at the time that this L concern was first identified, may have prevented this '
violation of Technical Specification Surveillance i
Requirement 4.4.7. Failure to perform an isotopic analysis
for iodine within 2 to 6 hours following a thermal power
change exceeding 15 percent of rated thermal power within a s
1-hour period is an apparent violation of Technical
Specification Surveillance Requirement 4.4.7 (445/9019-02).
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d. 'EGT-327A, " Steam Generator Atmospheric Relief Valve ;
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,
Capacity Test." -
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On May-21, 1990, after completing the capacity test'of all' :
four atmospheric relief valves (1-MS-257, -258, '
-259,and -260), the licensee documented in ONE Form
FX-90-1602 that the capacity of one of the atmospheric
relief valves (ARVs) exceeded the review' criteria of 2.5
1 1% of total rated steam flow. Two and one-half percent of
total rated steam flow corresponds to approximately
378,500 lbm./hr. This review criteria was specified41n-
Testing Manual Procedure EGT-327A,- Revision 0, " Steam
Generator Atmospheric Relief Valve Capacity Test." As a i
result of this apparent overcapacity, an engineering :
H analysis was performed to determine if this condition was
acceptable. On the basis of this evaluation, it was
determined that the relief capacity for the three other ARVs.
was actually less than required because the review criteria
- of 2.5 i 1% of total rated steam flow.per ARV was incorrect.
The actual required ARV capacity was 779,000 lbm./hr. to
l~
968,000 lbm.'/hr. corrected to rated steam pressure .
(1200. psia). The minimum capacity for the ARVs was !
E determined on.the basis of a reevaluation of a portion of
the design-basis-steam generator tube rupture'(SGTR)' event-
discussed in FSAR Section 15.6.3. This revised information I
was reflected in Revision 3 of Design-Basis Document
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(DBD)-ME-202, " Main Steam, Reheat and Steam Dump System."
Discussions with licensee personnel revealed, however,.that
,
Revision 0 of EGT-327A was being drafted at about the same
L time that Revision 3 of DBD-ME-202 was-issued. As a: result, '
EGT-327A did not reflect the new requirement'for minimum ARV ,
'
capacity. Subsequent reevaluation by the licensee revealed
that the required ARV relief capacity was 750,000'lbm./hr.
to 968,400 lbm./hr., referenced to 1200 psia.
The stroke, lengths for the ARVs were actually adjusted in
February 1989 in accordance<with DCA 64209, Revision 1, to i
meet this new requirement. The required stroke length was ;
'
1 3/8"' valve stem travel which corresponded to approximately
779,000 lbm./hr. at 1200 psia main steam pressure. However,
in June 1989, the stroke lengths of 2 ARVs were incorrectly 1
set at 1 1/4" following corrective maintenance. As a result
of this, these 2 ARVs had insufficient capacity when they
were tested on May 21, 1990. A third ARV capacity was also
too low because it drifted out of calibration. Although the
licensee identified this problem and effectively resolved i
b it, it'does not appear that this incorrect ARV capacity ! L' review criteria would have been detected in a timely manner '
had the actual ARV capacity met the originally specified
review criteria.
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t Failure to provide adequate review criteria'for Procedure ~ .^
'EGT-327A is an; apparent violation of 10-CFR Part 50,-
Appendix B,. Criterion V (445/9019-03).
'
e. ISU-213A, " Design Load Swings Test."
. l
The licensee performed several 10-percent turbine load-
swings between approximately 35 and;50-percent reactor
power. . The plant responded-as expected during.this-test, l
and the test was well executed.
i f. -ISU-226A, " Operational Alignment of Process Temperature and
'
N16 Instrumentation."
D
g. .ISU-224A, " Thermal Power Measurement and Statepoint Data
'
Collection."
h. ISU-207A, " Steam Generator Level Control System Test'.'
In summary,:although there were two problems, licensee
. coordination and control of these tests were excellent,
-particularly, the conduct of the turbine trip coincident with.a- ,
loss of offsite power test.
8. Onsite Followup of Written Reports of Nonroutine Events (92700)
The inspector reviewed the below listed'LER to determine whether ,
'
corrective actions were taken as stated, and whether response to
the events was adequate and met regulatory requirements, licensee
conditions, and commitments. s
(Closed) LER.50-445/90-009-00, " Reactor Trip due to Accidental'
Bumping;of' Source Range Reactor Trip Reset / Block Switch."
This.LER' documented a. reactor trip that occurred.on April 21,
'1990, when a Reactor Operator inadvertently bumped switch
1/1-N-33B while' dusting the main ~ control board and reset Source
Range Channel N31 which had been previously bypassed for power ;
operation. Corrective actions for this event-included the
removal.of cleaning brushes from the Control Room and installing
plastic covers over the switches. Additionally, the licensee is
performing an evaluation to determine if Switch 1/1-N-33B is
'Y overly sensitive and why bumping the switch caused the Source
Range Channel'to reset. This LER is~ considered closed.
:
1 No violations or deviations were identified.
9. Followup of Previously Identified Items (92701)
a. (Closed) Open Item (445/9007-0-01): This open item
identified inconsistent valve capping requirements in System i
Operating Procedure (SOP)-502A and Operations Testing l
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9 ProcedureL(OPT)-219A. Additionally, records showed~that.the' l
,L ._ shift supervisor approved a valve lineup showing'an_ apparent .
The licensee issued One
'
. valve' capping. discrepancy.
. Form FX-90-11421to address _the procedural' discrepancies.
.These corrections were made with the' issuance of ,
PCN-OPT-219-1-R2-2. Office Memorandum CPSES-9011049 '
,
documented the licensee's corrective actions in response to
*
'the incorrect approval, which included a discussion with all- '
shift supervisors and a statement placed in the' night :
orders. The inspector reviewed PCN-OPT-219-1-R2-2:and i
Memorandum CPSES-9011049 and concluded that the licensee had- i
taken sufficient-corrective actions. This open item is
closed.
b. (Closed) Open Item (445/9013-0-01): Licensee to resolve
observations and weaknesses associated with Initial Startup i
Test Procedure ISU-223A, " Remote Shutdown Capability Test,"
prior to; conducting the remote shutdown capability test.
The licensee adequately addressed all the concerns
associated with this item; therefore,-this item is closed.
'
No violations or deviations were identified.
.. 10. Licersee' Action'on'10 CFR Part 50.55(e) Deficiencies (92700)
a. _(Closed) Construction Deficiency (SDAR CP-87-27): " Galvanic
Corrosion in Service Water System." This issue originated ;
when a-design validation revealed that flow elements
installed in the service water system were constructed of-
monel. material while theirLpiping mating flanges are carbon .
steel. The concern was that the dissimilar' metals'would
.cause galvanic corrosion.
The licensee determined that this condition was not.
I reportable under the provisions of 10 CFR 50.55(e)., This
decision was made on the basis of an evaluation that .
concluded that the corrosion rate would be very small' !
Furthermore,'any minor leakage would not adversely affect
f the service water system.
'
l' j To correct'the problem, the~ licensee installed plastic ' '
, insulating sleeves on-the-flanges of the flow elements. The
Li inspector reviewed the documentation associated with the f corrective action and found it to be adequate. This item is
closed.
[[ h, K b. (Closed - Unit 1 only) Construction Deficiency I
(SDAR CP-90-01): "Feedwater Isolation Valve Impact
l
Testing." Feedwater isolation valve (FWIV) pressure
retaining ferritic materials were not impact-resistance
tested per the ASME Boiler and Pressure Vessel Code as
originally committed to in the FSAR. The licensee performed
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; supplementa1Limpact testing and fracture-analysis-of the' ;
FWIVs. The resultin'g pressure-temperaturellimitations on
'
the FWIVs-were incorporated into the Technical Requirements -
Manual. In Section 10.3.3'of NUREG-0797, Supplement No. 24, ,
the NRC staff concluded that these' changes were acceptable. 1
. The licensee installed Design Modification (DM) 89-430 to
e 5 install strip? heaters and temperature monitoring on:the '
FWIVs.- .Following this installation, testing was' performed
,
4
per. Procedure EGT-TP-90A-1. The inspector reviewed the: ;
completed test package. This test demonstrated that the-
'
heater-units'wereabletomagntain'valvebodyandbonnet.;,
/ temperatures greater than 90 F.
. .
O J However,.while observing control room operations activities,
the inspector reviewed Operations Department. Test Procedure-
OPT-102A-7, Revision 4,." Local Shiftly Surveillance." .The
inspector ~ observed that the local'shiftly surveillance log i
sheet had been recently changed to require-the reccrding of 4
- FWIV-temperatures in Mode 1 when.the FWIVs are closed. . 4
,
a Prior to the change, FWIV temperature was observed and
. Llogged when the plant was operating in Modes 2 and 3. The
' FWfVs .are required to be maintained equal ta) or greater than
90 F'in'accordance wi'th Technical-Requirements Manual-
(TRM) 3.3. .This. requirement ensures that the structural
integrity-.of-the FWIVs is maingained when FWIV temperature'
'
l 1s: equal to or greater than 90 F-and main feedwater~ system
"; pressure:is greater than 675 psig. TRM 3.3 is applicable in
~ -
u Modes 1, 2, and 3. U DJ TRM 3.3 was changed to require surveillance of FWIV L temperature with the plant inl Mode 11 after it was discoveged
on April 28, 1990, that.the No. 2 FWIV (1-HV-2135) was 88-F
! .as. indicated by temperature element 1-TE-2178B. Upon i
discovering this g condition, the licensee restored the No. 2 -
'
FWIV to above 90 F within.four minutes and performed a
subsequent engineering evaluation as. directed by compensa-
tory measure B of TRM 3.3. This evaluation concluded that
the likelihood of extensive' crack.propaggtion of FWIV No. 2
was small~even though temperature was 88 F and MFW-system
pressure was significantly greater than 675 psig.
The inspector questioned the licensee as to whether the
requirements of TRM 3.3 were satisfied on April 28 6 1990,
following the discovery that the No. 2 FWIV was 88 F.
Compensatory measure A of TRM 3.3 requires tgat with one or
more feedwater isolation valves less than 90 F, reduce the
main feedwater pressure to less than or equal to 675 psig
< within 30 minutes or be in Hot Standby within the next
6 hours and in Hot Shutdown within the following 6 hours.
Compensatory measure.B of TRM 3.3 requires that an
engineering evaluation be performed to determine the effect ,
of the overpressure on the structural integrity of the main
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feedwater isolation valves, and that the-feedwater isolation
. valve remains acceptable for continued operations-prior to
4 -i increasing MFW pressure.above 675 psig.- Instead of reducing
MFW system pressure to below 675 psig and performing an
" engineering evaluation,othe licensee restored'the No. 2 FWIV-
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: temperature-to above.90 F without reducing MFW system
pressure (which was approximately 1150 psig) and then
subsequently performed a' technical evaluation.
'
O Discussions with licensee-personnelirevealed that1they
considered this-action an acceptable alternative. 'They-
stated that the basis for:this action was similar to that
"
provided in' Technical' Specification (TS) 3.02 which states,
in.part, that if a Limiting condition for operation (which
'isLsimilar to a TRM requirement): is restored prior to
expiration of the specified time-intervals, completion of
the ACTION requirements (similar to TRM compensatory
measures)'is not required. Thelicenseestatedthatsgnce >
FWIV No-2 temperature was restored to greater them 90 F
within 30_ minutes, MFW system pressure did not have to be
reduced below 675 psig. Additionally, theylnoted that
compensatory measure A of TRM 3.3 would have to be changed
because: main feedwater system pressure.cannot be reduced
below-675 psig'with the plant remaining in Mode 1. t
=The inspector noted, however, that the Technical
Requirements Manual contained no written guidance that was
similar in-content to TS-3.02.- Further, discussions with
-
'
-licensee personnel revealed =that it was not' clear to what
extent the TRM was similar to the Technical-Specifications
in terms of control =and implementation. Because of this
, apparent lack of written. administrative guidance associated L with the Technical-Requirements, this issue'will be tracked !
"
! by an inspector followup item and reviewed during future ; i inspections (IFI-445/9019-04). - b
c. (Closed - Unit 1 only) Construction Deficiency
9 (SDAR CP-90-06): "6.9kV Loose Auxiliary Switch Linkage." l I This construction deficiency concerned a reportable event i involving the 6.9kV switchgear Type L2 auxiliary switches.
,
Specifically, while troubleshooting Class lE 6.9kV
p' switchgear breaker-leal-2, two-breaker auxiliary switches
04 (one in.the residual heat removal [RHR] pump cubicle and one
g in the containment spray pump No. 1 (CSPl]' cubicle) were Q" found to have loose mechanical linkages. ,g
4
'
As stated in the licensee's response to this event contained
in their letter,TXX-90109, dated April 9, 1990, further i
7 evaluation of this condition indicated that the holding nut
> behind the lever arm was missing on the csp 1 switch and was
loose on the RHR pump switch. As determined by the
,
inspector, the mechanical linkage utilized on the Type L2
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auxiliary switches ar9 employed to provide relay logic 'I
circuitry inputs-of: breaker position. Accordingly, the- H
failure-of the auxiliary switch could have affected the
,
operability of the associated logic circuits which utilize
'
the auxiliary switch contacts for input.
In order to evaluate the adequacy of the licensee's actions 1
relative to this event, the inspector reviewed the pertinent j
documentation-including Test Deficiency Report No. 8372; ONE l
Forms FX 90-776, -687, and -1131; Reportability Evaluation. I
Form 1SN-485; SDAR Final'Feport (Unit =1) CP-90-06; Root Cause i '
Investigation of FX-90-766; and CPSES Electrical Maintenance-
~ Procedure No. MSE-PO-6000.- I
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Subsequent to a review of the above documents'and an or. site
examination of the mechanical' linkage utilized on the- .
l
. Type L2Lauxiliary switches, the inspector determined that ,
the licensee had replaced the missing nut on.the CSP 1 switch l
and had tightened the loose-nut on the RHR pump, switch.. I
Additionally,'both the safety-related and the. i
i nonsafety-related 6.9kV'switchgear cubicles"for Unit 1 were
examined by electrical maintenance-to verify the tightness
of the hexagonal stud nuts on the auxiliary contact switch j
lever arms and torque-seal was applied. Also, Procedure
MSE-PO-6000, which establishes periodic. preventive
maintenance requirements for cleaning and inspection of'the:
6.9kV switchgear, was revised to. include inspection of the
auxiliary contact switch' linkage.-
.
These corrective and preventive actions along with
TU Electric's recommendation to the vendor, ASEA Brown
Boveri (ABB) that.these occurrences.be evaluated under ABB's
~
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10 CFR 21 program constitute an adequate response to this
construction deficiency for Unit'l. Therefore, this SDAR is -
L closed for Unit 1. However, pending-the-implemen.tation'of I
similar corrective actions for the Unit 2 6.9kV switchgear, ;~
l this item will, remain _open for Unit 2.
No violations or deviations were identified.
1
11. Licensee Planstfor Copino with Strikes (92709) ,
,
The inspector reviewed-the licensee's provisions and programs for
i coping with an imminent or impending strike to ascertain if
appropriate contingency plans had been prepared and to determine
if the contents of the strike plans were consistent with
regulatory requirements. The inspector participated in several
discussions with plant management personnel to determine
TU Electric's ability to maintain the minimum number of qualified
and proficient personnel available to ensure proper plant
operation and that plant security is maintained.
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As a:resulttof these discussions and other inspection related
activities, it was determined that the licensee has recontly
completed contract negotiations involving a six-month contract
for various plant personnel represented by the International
Brotherhood of Electrical Workers. Under the provisions of this
contract,_the utility's management would receive. notification
from the- subject union representatives prior to any strike -
related activities. As stated by the_ licensee, this contract
-provision would allow for the development of necessary strike
contingency plans. However, at the conclusion of.this reporting
period, no detailed strike plans or procedures existed which
delineated the required operations or support organization
. actions. Therefore, pending the development.of acceptable
proceduralized strike contingency plans, this item is identified
as:an inspector followup item (IFI 9019-05).
12. Unit 2 Walkdowns (70302, 71302)
During this inspection period, routine tours of the Unit 2
facility _were conducted in order to assess equipment conditions,
security,-and adherence to regulatory requirements. In
particular, plant areas were examined for evidence of fire
hazards,. installed instrumentation damage, and'to determine the
acceptability of system cleanliness controls and general-
housekeepi.ng. Additionally, the inspector conducted evaluations
of existing plant programs for the preservation and maintenance
>
of installed systems and components-as well as the utility's
preparations for the resumption of construction activities for
Unit 2.
As a result of these inspection activities, it was accertained
that the licensee resumed engineering work activities on Unit 2
on. June 4, 1990. In particular, as-stated in TU Electric's
letter CPSES-9011718, dated May 13, 1990, the following. contracts
have been awarded relative to the design engineering scope of
work:
Scope A Piping and Supports .Bechtel
Scope B Systems Stone & Webster
Scope C Civil / Structural Impell
It was also-determined that Brown and Root will continue their
function as the construction contractor and N-Symbol certificate
holder and that Stone and Webster was awarded the contract to
provide Quality Control services.
Relative to the CPSES Unit 2 project status, all major activities
appear to be progressing as reflected in the licensce's weekly
project schedule package. Specifically, construction of the
protected. area warehouse which will include a material inspection
building and a material staging facility is currently on schedule
with completion targeted for the November 1990 time-frame.
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Additionally, limited construction support activities are under
way to accommodate planned engineering activities; however, as ,
stated by the licensee, Unit 2 construction efforts will not
resume for several months. This schedule is designed to allow l
for the completion of engineering design efforts and work package
review prior to the active resumption of Unit 2 construction
,
activities.
While performing a routine plant tour of the Unit 2 vital battery I
rooms, the inspector observed that the Train A battery (2-ED-1) ,
was well below the required electrolyte level. This condition
'
was brought to the attention of electrical maintenance personnel
who indicated that work order No. C89-17874 had been initiated to
remove the interconnection bars and remove / clean the subject '
battery cells. . Upon examination of the applicable quarterly
preventive maintenance records, it was determined that the low ,
'
electrolyte levels in the 2-ED-1 battery cells had been
previously identified and properly dispositioned for corrective
action. Additionally, it was determined that appropriate
availability and operability provisions had been established
relative to maintaining DC protective functions for the Unit 2 i
service water pumps as stipulated in the Unit 1 Technical '
Requirements, Section 3.2.
No violations or deviations were identified. p
13. Exit Meeting (30703)
,
The inspection scope and findings warn summarized on June 5,
1990, with those persons indicated in paragraph 1 of this report.
The licensee acknowledged the inspectors' findi'.igs. The licensee
did not identify as proprietary any of the materials provided to
or reviewed by the inspectors during thie inepection.
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