ML18152A540
| ML18152A540 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 05/26/1994 |
| From: | Belisle G, Branch M, Tingen S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A541 | List: |
| References | |
| 50-280-94-11, 50-281-94-11, NUDOCS 9406060225 | |
| Download: ML18152A540 (12) | |
See also: IR 05000280/1994011
Text
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/94-11 and 50-281/94-11
Licensee:
Virginia Electric and Po~er Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted: April 3 through May 7, 1994
Inspectors:
M. W. Branch, Senior
Inspector
Resident
S. G. Tingen, Resident Inspector
Accompanying Personnel: D. M. Tamai
L. W. Garner
Approved by:
G. A. VBe l isle, Sec'ffinCief
Division of Reactor Projects
SUMMARY
Scope:
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Date Signed
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Date Signed
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Date Signed
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance and surveillance
inspections, and on-site engineering review.
Results:
Operations functional area
The continued use of the not applicable prov1s1ons in procedure STP-33.6,
Instrument Air Slowdown, revision 2, resulted in not correcting deficiencies
in the procedure (paragraph 3.b).
P9DR406060225 940526
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2
Maintenance functional area
The post maintenance tests performed after replacing several Unit 1
consequence limiting safeguards relays did not fully verify, by testing, that
proper circuit continuity existed .. Relay bench testing and second party
verification of field wiring terminations provided an adequate confidence
level that the relays were properly installed (paragraph 4.b).
Engineering functional area
The failure to revise the Unit 1 steam flow calorimetric computer program to
incorporate changes implemented by Engineering Calculation EE-0418 prior to
unit restart following the refueling outage was identified as Violation
50-280/94-11-01 (paragraph 3.a).
A weakness in the operational readiness review process was identified. A non-
safety related procedure was not recognized as needing revision after the
hardware was changed/removed by plant modifications. Additionally, a system
engineering review of completed surveillance test procedures did not identify
the need to change the procedure (paragraph 3.b).
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- D. Christian, Assistant Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
J. Downs, Superintendent of Outage and Planning
D. Erickson, Superintendent of Radiation Protection
A. Friedman, Superintendent of Nuclear Training
- B. Hayes, Supervisor, Quality Assurance
- D. Hayes, Supervisor of Administrative Services
- M. Kansler, Station Manager
C. Luffman, Superintendent, Security
- J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
R. Saunders, Assistant Vice President, Nuclear Operations
E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
J. Swientoniewski, Supervisor, Station Nuclear Safety
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- A. Belisle, Section Chief
- M. Branch, Senior Resident Inspector
- D. Tamai, NRC Intern
- S. Tingen, Resident Inspector
- Attended Exit Interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Units I and 2 operated at power for the entire inspection period.
Unit 2 operated at reduced power due to steam generator level
oscillations.
2
3.
Operational Safety Verification (71707)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indication to assess operability.* Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
a.
Operation of Unit 1 Above Licensed Maximum Power
On March 31, DR S-94-0804 was written to document a condition
where Unit 1 operated for a period of 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and 12 minutes above
the licensed maximum power level of 2441 MWT.
Specifically, at
2:18 p.m. on March 30, reactor power based on the power range Nis
and the CALCALC computer program, was increased from 98% to 100%.
The unit had just completed a RFO and this was the first time the
unit had operated at full power following the RFO.
At 100%
reactor power, operators noted that the turbine generator
electrical output of 830 to 835 MWE was higher than normal and
also exceeded the design value of 828 MWE.
The unit operated at
this power level until 8:54 p.m., of the same day, when management
ordered power to be reduced in order to investigate the
discrepancies between indicated NI reactor power and turbine
output. At 9:30 p.m. on March 30, reactor power was stabilized at
98.3%.
The licensee later confirmed that Unit 1 had operated for
one shift at an average power level of 2453 MWT which exceeded the
maximum licensed power level of 2441 MWT.
On March 31 a reactor
power calorimetric was performed utilizing feed flow.
The power
range Nls were adjusted based on the results of this calorimetric
and the unit was then returned to full power operation.
On that
same day the steam flow calorimetric computer program was revised .
. Through subsequent reviews, the licensee concluded that the power
range Nls were not indicating the correct power level at full
power.
The Nls were indicating approximately 1% lower than the
actual power level. During the 1994 Unit 1 RFO, the main steam
flow transmitters were respanned and the main steam flow
instruments were rescaled. The steam flow calorimetric computer
program was not revised to incorporate these new parameters.
As a
result the power range Nls did not indicate the correct power
level because at approximately 85% reactor power they were
adjusted to match reactor power that was calculated based on the
inaccurate steam flow calorimetric computer program.
TS Table
4.1-1 requires NI power be verified daily against a heat balance
standard (calorimetric calibration). The licensee's method for
3
performing the TS required heat balance surveillance used the
CALCALC computer program and was contained in procedure
1-0PT-RX-001, Reactor Power Calorimetric Using CALCALC Computer
Program, revision 1.
The licensee performed RCE 94-11, Surry Unit 1 Operation Above
100% Power, in order to investigate this event.
The inspectors
also reviewed the circumstances surrounding this event.
RCE 94-11
concluded that root cause of this event was that the process for
implementing changes to instrumentation based on revised
Engineering Calculation EE-0418, Determination of Feedwater Flow
and Steam Flow Transmitter's Calibration Spans from CHEMTRAC and
Flowcalc Data Resulting from Special Test 1-ST-300, revision 1,
was not adequately coordinated.
In this case the process did not
ensure that the steam flow calorimetric computer program was
revised prior to unit restart following the RFO.
The inspectors
reviewed RCE 94-11 and considered it to be comprehensive and
thorough.
The RCE also identified other examples where the lack
of a formal process for controlling and implementing calculation
changes resulted in problems at Surry and North Anna power
stations. The RCE and corrective actions to formalize the process
were approved by SNSOC on April 28.
During this event the power range NI high flux, Overpower Delta T,
and Overtemperature Delta T protective settings were in error by
approximately 1% in the nonconservative direction. The inspectors
reviewed the licensee's policy for reactor trip protective
settings which required that 2% margins be established between
actual settings and TS limiting settings. The inspectors
concluded that the TS limiting settings were not exceeded during
this event.
During the 1992 Unit 1 RFO, feedwater flow measurements were
obtained by using a chemical trace via procedure CHEMTRAC,
revision 1.
These precision feedwater flow measurements were
analyzed by electrical engineering via Engineering Calculation
EE-0418 and were used to revise steam and feedwater flow
instrument scaling values during that outage.
During the recent
1994 Unit 1 RFO, main steam flow scaling values were further
refined in accordance with revision 1 to EE-0418.
The refined
main steam flow scaling values were implemented but the steam flow
calorimetric computer program was not revised.
UFSAR Chapter 14, Safety Analysis, describes the initial condition
at the onset of the accidents and transients analyzed.
Many
accident analyses assume a steady state power level of 102% since
that is the claimed accuracy of the calorimetric. The
calorimetric is the standard used to calibrate NI instruments and
thereby establish the setpoints of the safety actions that are
initiated from these instruments.
Some accident analysis state
that a power level of 102% of 2441 MWT (current license limit) was
assumed while others assumed 102% of 2546 MWT (engineering safety
b.
4
feature rating). The licensee indicated that all accident
analyses had been re-performed using the 2546 MWT rating although
this rating was not recognized in the current UFSAR revision.
The steam flow values used in the Unit 2 calorimetric were
reviewed and the inspectors verified that a similar condition did
not exist. Specifically, during the Unit 2 1991 RFO, the
feedwater flow venturis were replaced and a special test was
performed to verify calibration curves for the new venturis.
Main
steam flow scaling deficiencies were identified and corrected as a
result of this modification and this issue was discussed in NRC
Inspection Report Nos. 50-280, 281/91-21.
The Unit 2 steam and
feed flow calorimetric computer programs were properly revised.
10 CFR 50, Appendix B Criterion III, Design Control, as
implemented by section 17.2.3 of the Operational QA Program
Topical Report, VEP-1-5A (Updated), requires that measures be
established to assure that design requirements be correctly
translated into specifications, drawings, procedures, and
instructions. Electrical Engineering Implementing Procedure
EE-029, Calculation Controlling Procedure, revision 2, stated
scope (2.2) requires that calculation results be effectively
communicated to the applicable power station.
The failure to
revise the Unit 1 steam flow calorimetric computer program to
incorporate the changes implemented by Engineering Calculation
EE-0418, revision 1, prior to restarting the unit following the
RFO was identified as Violation 50-280/94-11-01, Failure To Revise
The Steam Flow Calorimetric Computer Program.
ESF Walkdown
The inspectors walked down portions of the Unit 1 and Unit 2
compressed air system.
The primary purpose of the system is to
provide pressurized air to pneumatically operated valves.
The
walkdown included the service, instrument, and containment air
compressors, instrument and service air receivers, and instrument
air dryers and filters. Major system valves were verified to be
positioned in accordance with procedure OP-46.lA, Instrument and
Service Air Compressors No.2 Turbine Building/Outside Valves
Alignment, revision 8, and system drawings.
During the walkdown,
the inspectors verified that valves were properly aligned and
locked as required, air lines were adequately supported, no
deficient physical conditions were present, housekeeping was
acceptable, and breaker positions were proper on equipment not in
operation.
Ten incidents of incorrect or missing tags were
identified by the inspectors and provided to the licensee for
correction.
The system engineer was interviewed on system operability, recent
modifications and outstanding maintenance items.
The inspectors
also walked down part of the system with the system engineer.
The
service air compressor control cabinets were opened and inspected
5
for adequate housekeeping and equipment material condition.
The
inspectors concluded that the system was being adequately
maintained.
Monthly surveillance procedure STP-33.6, Instrument Air Slowdown,
revision 2, test results from 12/93 to 4/94 were reviewed.
Two
examples were identified where the STP was not updated after
modifications to the plant were implemented.
The first example
was DCP-93-040, BS Groundwater Intrusion and Control, revision 6,
which removed valve 1-IA-735.
The Design Change Process, as
outlined in VPAP-0301, revision 3, is intended to identify
affected drawings and procedures.
Per the design change process
an ORR initiates the update of affected priority documents.
The
ORR for DCP-93-040 did not identify procedure STP-33.6 as an
affected procedure.
The second example involved DCP-90-08, MER-5
Chiller Installation - CR HVAC Upgrade, revision 38, which changed
valve 2-IA-211 from a test connection to a non-testable IA supply
valve to MER #5.
STP-33.6 was annotated for three consecutive months with N/A
instead of correcting the procedure, and in some cases alternate
test valves were utilized. The procedure allowed omission of any
valves at the discretion of the shift supervisor provided that an
explanation was given. A liberal use of these instructions
allowed Operations personnel to N/A valves that were not testable
and continue the surveillance without a procedure change.
Furthermore, the system engineer reviewed each completed procedure
through a post-surveillance critique and did not initiate a
procedure change.
The inspectors identified a weakness in the ORR process, in that,
non-safety related procedure STP-33.6 was not recognized as
needing revision after the hardware was changed/removed by plant
modifications. Additionally, Operations personnel's continued use
of ~he STP-33.6 N/A provision resulted in not correcting
procedural deficiencies and a system engineering review likewise
failed to identify the need to change the procedure.
Within the areas inspected, one violation was identified.
4.
Maintenance And Surveillance Inspections (62703, 61726} .
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
a.
Unit 1 A Reactor Trip Breaker
On April 12, while performing monthly l-PT-8.1, Reactor Protection
System Logic (for normal operation}, revision 6, the Unit 1 A RTB
failed to remain closed. The breaker had successfully closed
twice earlier in the procedure.
The A RTB was removed for repair
J
6
and replaced with the B RTBB.
Both the licensee and the vendor,
Westinghouse, determined that the C phase of the control relay
contact had insufficient contact tension. Additionally, the
vendor recommended that breaker closure timing be changed to
deenergize the closing.coil slightly after the breaker
mechanically latches. The inspectors observed the reinstallation
of the A RTB.
The B RTBB was removed from the A RTB position and
returned to its original position and the A RTB was reinstalled.
The work was done in accordance with procedures and adequate
coordination with the control room was noted.
The breaker was
successfully tested in accordance with l-PT-8.1.
The failure of the A RTB to remain closed also occurred on
March 24, 1994, during the monthly test, l-PT-8.2, Reactor
Protection System Logic {for shutdown), revision 4.
The cause was
diagnosed as a faulted latch pawl spring. After replacing the
spring, the breaker was tested satisfactorily and returned to
service.
b.
Unit 1 CLS Relay Replacement
In 1993, the licensee performed a Level 1 engineering study that
identified six Hi CLS relays in each unit that would result in a
reactor trip if a single relay failure occurred.
Prior to
performing this Level 1, several reactor trips occurred due to
single relay failures. During the Unit 1 spring 1994 RFO, these
six CLS relays were replaced.
In addition several other Hi CLS
relays and Hi-Hi CLS relays were replaced because the relays were
either chattering or had a crack in the coil case.
The inspectors
reviewed the maintenance, PMTs, and surveillances associated with
replacing relays 3/4-CLS-lA {WO 269580 01), 3/4-CLS-lB
{WO 269582 01), 3-CLS-lAM {WO 269581 01), 3-CLS-lBM
{WO 269583 01), CR-CLS-lAl {WO 269380 01), CR-CLS-1Bl
{WO 269589 01), CR-CLS-1B13 {WO 283983 01), CR-CLS-284
{WO 281784 01), and CR-CLS-2BM-X {WO 267272 01).
The relays were replaced in accordance with procedure
O-ECM-1801-01, Westinghouse Type BFD Relay Replacement,
revision 5, and in most cases old style BFD relays were replaced
with later model NBFD65NR relays. Prior to installation, each
relay was bench tested which included coil testing and
verification that the contacts opened and closed as required.
Since the new relays had a different contact configuration, the
system engineer specified the wiring configuration for each relay
O-ECM-1801-01 attachment 2.
The electricians who installed and
rewired the relays independently verified that the leads were
installed to the relay terminals as specified.
The PMT sheets for replacing Hi-Hi CLS relays CR-CLS-2B4 and
CR-CLS-2BM-X required that the relays be tested in accordance with
l-PT-8.5, Consequence Limiting Safeguards Logic {HI-HI Train),
revision 2.
The inspectors reviewed 1-PT-8.5 performed on
7
March 21, 1994, and concluded that the relays had been properly
tested.
The PMT sheets for replacing Hi CLS relays 3/4-CLS-lA, 3/4-CLS-lB,
3-CLS-lAM, 3-CLS-lBM, CR-CLS-lAl, CR-CLS-1Bl and CR-CLS-1Bl3
required that the relays be tested in accordance with l-PT-8.4,
Consequence Limiting Safeguards (Hi-Train), revision 2.
The
inspectors reviewed l-PT-8.4 performed on March 20 and 21, 1994,
and identified the following examples where operation of specific
relay contacts were not verified while performing this test:
RELAY
TRAIN
CONTACTS
FUNCTION
3-CLS-lAM
A
18,22
Actuate Hi CLS
19,23
3-CLS-IBM
B
18,22
Actuate Hi CLS
19,23
CR-CLS-lAl
A
1, 5
Actuate SI-CLS
CR-CLS-1Bl
B
1,5
Actuate SI-CLS
On May 11 the licensee discussed with the NRC the installation and
testing performed on the above relays. After consultation with
Region II management and cognizant NRR personnel, the inspectors
concluded that the bench testing performed on these relays prior
to installation combined with the testing performed after
installation provided an adequate level of confidence that these
relays were properly installed. The inspectors also concluded
that the CLS relays were installed and tested in accordance with
the licensee's PMT program.
No discrepancies were identified.*
Within the areas inspected, no violations or deviations were identified.
5.
On-Site Engineering Review (37551)
Seismic Qualification of the Turbine Building
During an UFSAR review, the inspectors observed in Table 15.2-1 a note
concerning the turbine building that stated, "By design, building
collapse will not damage any Class I structures and components during
earthquake, or tornado-resistant structures and components during
tornado." The inspectors inquired if this statement meant that the
turbine building was seismically designed.
Per UFSAR section 9.10.4.18,
safety related equipment located within the turbine building includes
control room and switchgear area emergency ventilating units, component
cooling water heat exchangers, instrument air compressors, service water
valves, and charging pump cooling water and service water system valves
along with related cables/cable trays.
No areas of the UFSAR reviewed
by the inspectors referenced the turbine building as being seismically
qualified.
..
8
On March 31, 1994, the inspectors met with the licensee's Supervisor of
Station Civil Engineering, Supervisor of Corporate Civil Engineering,
and the Supervisor of Corporate Engineering Mechanics to discuss this
apparent conflict in the design basis. During this discussion, the
following information documented in Calculation 11448 was presented:
The turbine building was designed for normal wind loading
(150 mph) considering full sail area of the siding.
The major
turbine building structural elements were designed for tornado
wind loading. The controlling turbine building loading was found
to be the tornado wind pressure applied to the major structural
elements.
A comparison of loads generated by tornado wind pressure and
seismic motion revealed that the tornado loads would be several
orders of magnitude higher.
The licensee concluded from this
calculation that no specific analysis to seismically qualify the
turbine building was necessary.
Discussion of the calculation
revealed that while the turbine building side panels may be blown
away during a tornado the building structural steel should remain
intact.
The inspectors reviewed pages 105-110 of Calculation 11448 which was
performed by Stone & Webster in July 1967.
This calculation concluded
that the turbine building structural loads associated with an earthquake
were less than the loads associated with a tornado (the limiting design
for the turbine building).
The inspectors further discussed the seismic adequacy of the safety
related equipment and the raceway systems inside the turbine building.
The following information and conclusions were discussed:
The licensee used EPRI report NP-7150-D, The Performance of
Raceway Systems in Strong-Motion Earthquakes, as a reference when
evaluating the seismic adequacy of the raceway system within the
turbine building. The measurement of the peak ground
accelerations in the seismic events discussed in this report
varied from 0.12g to 0.85g.
Seismic damage was limited to only a few items except for sites in
excess of 0.55 peak ground acceleration. Surry's peak ground
acceleration is 0.15 and therefore not likely to suffer notable
damage from a seismic event.
The inspectors reviewed EPRI Report NP-7150-D which demonstrated the
types of damage to electrical raceways and electrical conduit that could
be expected during specific seismic events. The licensee plans to use
this information in further reviewing the adequacy of raceways.
In December 1980, the NRC initiated USI 46, Seismic Qualification of
Equipment in Operating Plants, to address seismic adequacy of mechanical
and electrical equipment in older nuclear plants such as Surry.
The
9
inspectors discussed the walkdowns that are presently in progress (to be
completed by the end of 1995) for the electrical and mechanical
equipment that are required for the safe shutdown of the plant. These
walkdowns should verify the seismic adequacy of this equipment and
raceways.
Another objective.of this program is to verify the
interaction of non-safety related (and non-seismic) equipment and safety
related equipment.
The industry's efforts (SQUG) are for resolving USI
A-46 and IPEEE (seismic) issues.
Qualification of Personnel
The inspectors reviewed the qualifications of the three individuals
described above who were involved in resolving the seismic issues at
Surry. All of the individuals met the supervisory qualifications
required by ANS 3.1 and SQUG for seismic capability engineer.
The
requirements are as follows:
ANS 3.1, Standard for Qualification and Training of Personnel for
Nuclear Power Plants, stated that supervisory personnel should
have a BS in Engineering and should have six years of professional
level managerial experience in the power field.
In addition,
several of the individuals possessed PE licenses.
SQUG procedure, Generic Implementation Procedure For Seismic
Verification of Nuclear Plant Equipment, had requirements for a
seismic capability engineer (Sec. 2.1.2). These requirements were
an engineering degree, or equivalent, completion of a SQUG
developed training course on seismic adequacy verification of
nuclear power plant equipment, and at least five years experience
in earthquake engineering applicable to nuclear power plants.
The inspectors had no further concerns in this area.
Within the areas inspected, no violations or deviations were identified.
6.
Exit Interview
The inspection scope and findings were summarized on May 10, 1994, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection results addressed
in the Summary section and those listed below.
Item Tvpe/Number
Status
VIO 50-280/94-11-01
Open
Description/(Paragraph No.)
Failure To The Revise Steam
Flow Calorimetric Computer
Program (paragraph 3.a)
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
\\. "
10
7.
Index of Acronyms and Initialisms
AMERICAN NUCLEAR SOCIETY
BS
BACHELOR OF SCIENCE
CFR
CODE OF FEDERAL REGULATIONS
CLS
CONSEQUENCE LIMITING SAFEGUARDS
CR
CONTROL ROOM
DESIGN CHANGE PACKAGE
DR
DEVIATION REPORT
EE
ENGINEERING EVALUATION
ELECTRICAL POWER RESEARCH INSTITUTE
ENGINEERED SAFETY FEATURE
g
GRAVITY
HEATING VENTILATION AND AIR CONDITIONING
INDIVIDUAL PLANT EXTERNAL EVENT EXAMINATION
MER
MECHANICAL EQUIPMENT ROOM
MWE
MEGAWATT ELECTRIC
MWT
MEGAWATT THERMAL
N/A
NOT APPLICABLE
NI
NUCLEAR INSTRUMENTATION
NRC
NUCLEAR REGULATORY COMMISSION
ORR
OPERATIONAL READINESS REVIEW
PROFESSIONAL ENGINEER
PREVENTATIVE MAINTENANCE TEST
PERIODIC TEST
QUALITY ASSURANCE
ROOT CAUSE EVALUATION
REFUELING OUTAGE
RTB
REACTOR TRIP BREAKER
RTBB
REACTOR TRIP BYPASS BREAKER
SAFETY INJECTION
SNSOC
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SEISMIC QUALIFICATION UTILITY GROUP
SURVEILLANCE TEST PROCEDURE
T
TEMPERATURE
TURBINE BUILDING
TS
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED SAFETY ISSUE
VIOLATION
WORK ORDER