ML20137M965
| ML20137M965 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 01/22/1986 |
| From: | Bearden W, Ignatonis A, Jenison K, Shymlock M, James Smith, Tgnatonis A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20137M932 | List: |
| References | |
| 50-327-85-46, 50-328-85-46, NUDOCS 8601290111 | |
| Download: ML20137M965 (24) | |
See also: IR 05000327/1985046
Text
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UNITED STATES
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NUCLEAR REGULATORY COf,IMISSION
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REGION 11
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101 MARIETTA STREET.N.W.
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ATLANTA, GEORGI A 30323
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Report Nos.:
50-327/85-46 and 50-328/85-46
Licensee: Tennessee Valley Authority
6N38 A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
Docket Nos.: 50-327 and 50-328
License Nos.:
Facility Name:
Sequoyah Units 1 and 2
Inspection Conducted: December 9, through December 13, 1985
Inspectors:
(I b. ,}lnn,Gh+th
ll00 R$
A. J. IgnatJnis', Gnypection Team Leader
Date Signed
C 6 4,da
iln/u
pK.M.JeniYon,SenthResidentInspector
Date Sfgned
6A
d n i nu
da1/n
g W. C. Beardert, Resi~deht Inspectnr
Date Signed
dd. CAD Dn
th a/r4
J. D. Smith,(Inspect}bn Specialist, 0IE
Date Signed
EPb&YrDt/td
^20-66
M. B. Shymlock / Senior Resident Inspector
Date Signed
Approved by:D . Weise, Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This special, announced inspection involved 210 inspector-hours onsite in
the areas of 50.54(f) letter followup and operational readiness verification
including, NRC Bulletins and Notices, Corporate and Sequoyah Nuclear Plant
Commitment Tracking Systems, Operating Experience Review, Reactor Trip Reduction
Program, Modifications, Surveillance Instruction review, and licensee's evalua-
tion of the Davis-Besse Event described in NUREG-1154
Results:
In the areas inspected, three violations with multiple examples were
identified:
1.
Failure to establish and maintain adequate surveillance and system operating
instructions (paragraphs 6.a. and 6.b.).
0601290111 060122
ADOCK 05000327
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2.
Failure to feplement procedures (paragraph 6.a).
3.
Failure to conduct adequate PORC reviews (paragraphs 10.a. and 10.b.).
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REPORT DETAILS
1.
Licensee Employees Contacted
- H. L. Abercrombie, Site Director
- P. R. Wallace, Plant Manager
- L. M. Nobles, Operations and Engineering Superintendent
- B. M. Patterson, Maintenance Superintendent
- J. M. Anthony, Operations Group Supervisor
- L. C. Bush, Operations Group Assistant Supervisor
- R. W. Olson, Modifications Branch Manager
- M. R. Sedlacik, Electrical Section Manager, Modifications Branch
- L. D. Alexander, Mechanical Section Supervisor
- M. A. Skarzinski, Electrical Maintenance Supervisor
- H. D. Elkins, Instrument Maintenance Group Manager
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G. B. Tiner, Instrument Maintenance Engineer
- M. R. Harding, Engineering Group Manager
D. C. Craven, Quality Assurance Superviser
- G. B. Kirk, Compliance Supervisor
- R. C. Birchell, Compliance Engineer
- R. W. Fortenberry, Engineering Section Supervisor
- R. M. Mooney, Systems Engineering Supervisor
- R. J. Griffin, NSRS Site Representative
- J. A. Dunlap, DPS0 Supervisor
- C. R. Brimer, Site Services Manager
- W. S. Wilburn, Technical Services Supervisor
- J. H. Sullivan, Regulatory Engineering Supervisor
- D. L. Cowart, Quality Surveillance Supervisor
- C
E. Bosley, Quality Assurance Auditor
- J. L. Hamilton, Quality Engineering / Quality Control Supervisor
- T. E. Burdette, Quality Assurance
- R. W. Moore, Quality Assurance Manager
- C. E. Chmielewski, Nuclear Engineer
- C. L. Wilson, Nuclear Engineer
Other licensee employees contacted included technicians, operators, shift
engineers, security force members, engineers and maintenance personnel.
NRC Resident Inspector
- S. P. Weise
- L. J. Watson
- Attended exit interview December 13, 1985
- Attended exit interview telecon January 14, 1986
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2.
Exit Interview
The inspection scope and findings were summarized with the Plant Manager and
members of his staff on December 13, 1985.
After Regional management
review, a telephone exit interview was conducted on January 14, 1986, to
further present the inspection findings.
Three violations with examples
described in paragraphs 6.a. ,
6.b.,
10.a. and 10.b. were discussed in
detail.
Four unresolved items were identified during this inspection and
are discussed in paragraphs 6.a
8, and 10.c.*.
The licensee acknowledged
the inspection findings.
Information on reactor protection setpoint
methodology was identified as proprietary, but is not incorporated in this
report.
During the reporting period, frequent discussions were held with
the Site Director, Plant Manager and his assistants concerning inspection
findings. At no time during the inspection was written material provided to
the licensee by the inspector.
3.
Licensee Action on Previous Inspection Findings (92702)
(Closed) Unresolved Item 327, 328/85-43-01, Failure to Update Procedure
S0I 30.6, Auxiliary Building Gas Treatment System (ABGTS).
Inspector review
of SOI 30.6 and ABGTS walkdown identified a discrepancy in the amperage
rating of fuses specified in 501 30.6 versus the ones installed in the local
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control panel for the ABGTS humidity control heaters.
The inspector
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reviewed ABGTS modification made in 1984 and upgraded this Unresolved Item
to a violation. Details are provided in paragraph 6.b.
4.
Licensee Commitment Tracking System
The licensee's commitment tracking system was reviewed to determine its
viability, extent and implementation.
The following documents were
reviewed:
a.
TVA's Nuclear Performance Plan submittal dated November 1,
1985,
containing Volume 1, the Corporate Plan and Volume 2, the Sequoyah
Plan.
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b.
TVA memorandum L44 850919 805, Policy Regarding Control Over Making
Commitments To The Nuclear Regulatory Commission, Tracking Commitments
Through Implementation, and Maintaining Commitments Throughout Plant
Life - H. G. Parris, September 26, 1985.
c.
TVA memorandum L44 850927 801, Policy Regarding Control Over Making
Commitments To The Nuclear Regulatory Commission, Tracking Commitments
Through Implementation, and Maintaining Commitments Throughout Plant
Life - W. T. Cottle, October 2, 1985.
- Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations or deviations.
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Volume 1, Section 3.2 of the Corporate Nuclear Performance Plan (NPP) states
that Sequoyah Nuclear Plant (SQN) is working on full implementation of the
corporate policy for maintaining all NRC commitments on the Corporate
Commitment Tracking System (CCTS).
Full implementation of the CCTS at SQN,
was to be completed by Dctember 31, 1985.
The corporate Nuclear Licensing
Staff (NLS) was assigned the responsibility of making initial entries into
the CCTS and ensuring that they have appropriate management review and
approval.
TVA memorandum L44 850927 801 provides program guidance for implementing the
corporate policy on commitment tracking.
Included in this letter is the
purpose of the CCTS and delineation of the TVA nuclear facility and Cor-
porate Nuclear Licensing Branch responsibilities.
The purpose of the CCTS
is to ensure that commitments to NRC are evaluated, approved, documented,
tracked, implemented, and maintained to ensure regulatory compliance.
The
SQN staff responsibilities are as follows:
a.
Make and/or modify commitments to NRC relating to SQN.
b.
Evaluate proposed commitments to ensure that they are necessary,
accurately defined, achievable, and sufficient to satisfy regulatory
requirements.
c.
Track, implement, and maintain continued compliance of NRC commitments.
d.
Maintain appropriate coordination of commitment actions with other TVA
organizations.
Although the CCTS was not fuTly implemented, the inspectors reviewed the
current SQN tracking system and compared it to the available CCTS.
Site
input to the formative stages of CCTS appeared minimal.
The SQN staff
appeared to have had little participation in the formative process. The SQN
staff was maintaining a separate computerized tracking system (Commitment
Action Tracking System - CATS) which they planned to use to support the
CCTS. The inspectors found that the format of the CCTS is incompatible with
CATS and that the information presented in CCTS is not detailed enough to
identify multiple facets within the same commitment.
The tracking identi-
fication numbers of the two systems used different numbering schemes to
itemize commitments.
Further, the inspectors found a lack of program
coordination between the corporate Nuclear Licensing Staff and the SQN
staff.
For example, SQN did not use the prescribed format for data entry
into the CCTS.
Instead, the locally generated CATS form was used. The SQN
use of the CCTS appeared to be in the input mode only.
The inspector discussed the above concerns with the SQN Site Director. The
SQN Site Director acknowledged that the SQN staff does not use the pres-
cribed format input for CCTS and that there is format incompatibility
between CATS and CCTS.
The Site Director indicated that the CCTS Corporate
policy would be properly implemented at SQN by December 31, 1985.
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As reviewed, neither the CCTS or the CATS addresses written commitments that
are completed based on exit interview information and prior to the issuance
of an NRC violation response. This means a record of the commitment and its
completion is not preserved.
If a commitment required future repetitive
actions (i.e., training, operator experience review, Health Physics audits,
etc.), these future actions would not appear in either system because the
item would be closed when the commitment was met initially.
The definition of commitment per TVA memorandum L44 850927 801, is a written
and docketed statement of TVA actions taken or to be taken by some future
date.
By this definition, written TVA commitments can encompass a variety
of subject items which should include FSAR commitments, written licensee
commitments on which SER assumptions were based, responses to deviations,
and written commitments made in response to NRC/TVA meetings and NRC
letters.
Hence, according to the commitment definition, the scope of the
commitments can be very broad.
To address the potential of missed commit-
ments at SQN the licensee comitted in SQN NPP, volume 2, to review past
NRC commitments back to January 1,1981, in the areas of past violation
responses
IE Bulletin responses, licensee event reports, and NUREG-0737
items. TVA will review the above items prior to unit startup.
The SQN staff was developing an implementing policy Standard Practice
(SQA-135) to support the CCTS.
This procedure was in the review process at
the time of this inspection.
The NRC will review this implementing policy
and verify implementation of CCTS per SQA-135 after the program is imple-
mented.
The licensee also had not established a system for independent
verification of commitment completion at the time of the inspection.
This
is an Inspector Followup Item (327,328/85-46-01).
5.
IE Bulletin No. 85-02, Undervoltage Trip Attachments on Westinghouse DB-50
Type Reactor Trip Breakers
The inspectors reviewed the IE Bulletin and the licensee's response letter
dated December 3,1985.
The licensee committed in their response to IEB 85-02 to install the automatic shunt trip modification on the reactor trip
breakers prior to the restart of each respective unit. The inspectors also
verified that the Main Feedwater System Isolation Valve, Feedwater Regula-
tion Valve, and Feedwater Regulation Bypass Valve electrical configuration
were as described in IEB 85-02 (reference: drawing 47W611-3-2).
In conjunction with the bulletin review, the failure of the undervoltage
output circuit boards in the Westinghouse designed Solid State Protection
System (SSPS), which was addressed in IE Information Notice 85-18 was also
reviewed. The following procedures were reviewed:
IMI 99 - SSPS, Reactor Protection System
TI 52, Special Instruction for Removing the SSPS from Service and
Returning it to Service.
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IMI 99 FT 18, Reactor Protection System Functional Test
SI-227, Response Time Testing Reactor Protection System Trip Function
SI-227.1, Post-Maintenance Response Time Test of Reactor Trip Breakers
RTA and RTB
Surveillance Instruction (SI) 227.1 requires that, after performance
of
maintenance on the reactor trip breaker or when the technician has reason
to believe that damage has been done to the protection circuit, Instrument
Maintenance Instruction (IMI) 99 FT 18 be performed.
SI 227.1 does not
require that this functional test be performed following trouble shooting in
the Solid State Protection System circuits. However, per the requirements
of IMI 99-SSPS, a functional test of the SSPS is performed after each
entry into the system controlled by a maintenance request.
The inspector
determined that adequate procedural controls existed for verifying oper-
ability of the reactor trip circuitry.
6.
Surveillance Instruction (SI) Verification
The inspectors reviewed the following sis which implement Technical Specifi-
cation surveillance requirements:
Surveillance Instruction
Title
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Shift Log
SI-2
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SI-3
Daily, Weekly, and Monthly Logs
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SI-6.1
Containment Building Ventilation Isolation
(100 Hr/7 Day)
SI-9
Actuation of Automatic Valves Via SI Signal
for Nontestable Boric Acid and ECCS Flow
Path Valves
SI-12
ECCS Valve Alignment Verification
SI-40
Centrifugal Charging Pump
SI-128
ECCS Residual Heat Removal Pumps
SI-129
ECCS Safety Injection Pump Operability
SI-137.02
Reactor Coolant System - Unidentified
Leakage Measurement
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SI-143
Control Building Emergency Air Cleanup
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System Filter Train Test Requirements
SI-144.1
Control Room Emergency Ventilation Automatic
Actuation
SI-166.10
Accumulator / Injection Primary and Secondary
Check Valve Integrity
SI-166.18
RHR Return Valve Leak Rate Test
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SI-168
Calibration of Control Room Air Intake
Chlorine Detection System
SI-240
Functional Test of Control Room Air Intake
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Chlorine Detection System
SI-256
Periodic Calibration Overcurrent Relays
and Distance Relays on 6.9KV Reactor
Coolant Pumps on 6.9KV Unit Boards
.SI-257
Periodic Functional of RCP Overcurrent
Devices (Refueling Cycle)
SI-258
Inspection of Molded Case and Lower Voltage
Circuit Breakers
SI-266
60 Month Circuit Breaker Inspection
SI-270
Inspection of Molded Case and Lower Voltage
Circuit Breaker Backup Fuses
SI-413
Hydrogen and Oxygen Level for Gas Decay
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Tank
Additionally, the inspectors reviewed the following calibration and
operating procedures:
Il11-92-PRM-CAL
Nuclear Instrumentation Channel Calibration
S01 30.1
Control Building and Control Room Heating,
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Air Conditioning, and Ventilation System
S0I 30.6
Auxiliary Building Gas Treatment System
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As a result of this review, concerns were noted in the following areas:
a.
SI-256, Periodic Calibration of Overcurrent Relay and Distance Relays
on 6.9 kv Unit Boards
TS 3/4.8.3 for operability and surveillance of Electrical Equipment
Protection Devices and Containment Penetration Conductor Overcurrent
Protection Devices was reviewed to determine specific testing require-
ments. Major differences were identified by the inspectors between the
TS requirements for Unit 1 and Unit 2 testing of the primary and
secondary protection devices of TS Table 3.8-1:
(1) For the Unit I reactor coolant pump penetration backup overcurrent
protective devices, the licensee sets the
trip setpoints at
20,000 amps instead of the 2,000 amps specified in TS Table 3.8-1.
Per discussion with the licensee, the backup device trip setpoint
values in the Unit 1 TS were identified to be incorrect, based on
the ncrmal current load through the breaker.
The backup circuit
breaker is the normal feeder breaker for the 6.9 kv unit board.
(2) The Unit 1 and Unit 2 primary device trip setpoint values are
inconsistent.
In the Unit 2 TS, only the instantaneous trip
feature (plunger) of the primary conductor overcurrent protective
device is specified for testing.
The Unit 1 TS requires testing
of only the delayed primary protective device feature (rotating
disc). The inspector determined that the licensee tests both trip
features of the primary protective devices on each unit.
The
location for the Unit 2 reactor coolant pump number 4 primary
and backup devices stated in the TS is PNL-9 on the 6.9-KV
Auxiliary Power Board 2D. The devices are actually located in PNL-7
of that board.
(3) The response time values in TS Table 3.8-1 for the primary
protective devices should have units of minutes instead of
seconds.
(4) These TS errors have existed since initial licensing of both
units.
The licensee submitted TS change request number 62 on
November 7,1984, which proposed deleting TS Table 3.8-1, but did
not address the above errors.
This proposed TS change request is
under NRC review.
The correction of TS Table 3.8-1 is required
prior to unit startup and is identified as an Inspector Followup
Item (327, 328/85-46-02).
Duc to inadequate and incorrect requirements identified in the current
TS Table 3.8-1 described above, the inspectors were unable to determine
if the intent of the TS and plant design were fully met by use of
procedure SI-256. Additionally, the licensee failed to seek correction
of TS Table 3.8-1 :for an inordinate amount of time.
These issues
constitute an Unresolved Item (327, 328/85-46-03) pending further
review of the licensee's testing methodology.
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SI-256 is performed to accomplish the surveillance requirement of TS 4.8.3.1.a.1(a).
The most current completed SI data package for SI-256
(dated October 1,1985) was reviewed by the inspector.
Item (2) in
Section I of the Acceptance Criteria of SI-256 required that the
primary overcurrent relays pickup and critical time are to be within a
tolerance of 5 percent of the trip setpoint values.
However, TS for
Unit 2 primary devices on the reactor coolant pump (RCP) containment
penetrations require a tolerance of 2 percent.
Item (2) also required
that the relay targets operate properly between 1.0 amp and 2.0 amp
with DC voltage applied.
However, the vendor instruction manual for
the General Electric type IAC66K relay indicated proper operation to be
between 0.1 amp and 2.0 amp.
Item (3) in Section I of the Acceptance
Criteria required that the distance relay, impedance circle show the
angle of maximum torque to be close to 75 degrees (phase angle). The
correct angle of maximum torque was actually verified at 105 degrees,
which is the proper value.
These invalid criteria constitute a
violation for failure to adequately establish a surveillance procedure
(327, 328/85-46-04).
As part of the corrective action, the licensee
should determine if this resulted in TS setpoint violations.
Further
examples of inadequate procedures are described elsewhere in this
report.
During the review of the completed Routine Relay Test Record sheets,
the inspector identified that recorded target settings documented
target operation at 0.2 amp.
Item (2) of the acceptance criteria was
signed off and verified by a second person that the 1.0 amp to 2.0 amp
requirement was satisfied, despite the 0.2 amp recorded value.
The
inspector could not ascertain the reason for this discrepancy.
The
inspector also found that the completed SI package had been reviewed
by both the section supervisor and quality assurance (QA).
These
verifications / reviews of the completed SI package and signoffs did not
identify that the acceptance criteria was not satisfied and did not
identify the procedural discrepancies.
This constitutes a violation
for failure to adequately implement the signoff and review provisions
of procedure SI-256 (327, 328/85-46-05). Additionally, several Routine
Relay Test Record sheets in the completed SI-256 data package had
numerous uncontrolled changes made to the Setting Record column
Instrument Setting parameter units.
This was due to the Test Record
sheet being a generic data sheet for all relays.
These procedure
changes were not controlled per AI-4 Plant Instructions - Document
Control for control of procedure changes.
Failure to implement pro-
cedure change requirements of AI-4 is a further example of violation
327, 328/85-46-05.
The licensee should address corrective actions to
ensure that employees understand the need to follow procedures or
properly correct them when technical errors exist.
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b.
System Operating Instruction (S0I) 30.6 for the Auxiliary Building Gas
Treatment (ABGT) system was compared to the as-built configuration of
the plant through inspector walkdown.
The inspection was performed as
a followup to a previous inspection of the ABGT system reported in
Inspection Report 327, 328/85-43.
The inspectors noted that S0I 30.6
specified fuses of a different amperage rating than those that were
actually installed.
This was identified as an Unresolved Item 327,
328/85-43-01 pending review of pertinent system modifications.
In
1984, the licensee approved and implemented Engineering Change Notice
(ECN) L 6278 which modified the ABGTS circuitry for humidity control.
The inspector reviewed S0I 30.6 for compatibility with these ABGTS
modifications.
The procedure was found to be deficient in the
following areas:
(1) The procedure listed vent boards 2B1-B and 2Al-1 as having three
FRS 45 ampere fuses. Fifty ampere fuses were actually installed.
The installed fuses were verified by the inspector to be the
required fuses, based on modifications performed under Engineering
Change Notice (ECN) L 6278 and Work Plan 11326.
(2) The procedure listed vent boards 2B1-B and 2Al-1 as having three
KTN 2 ampere fuses. One ampere fuses were actually installed. The
installed fuses were verified by the inspector to be the required
fuses, based on ECN L6278 and Work Plan 11326.
(3) The procedure prescribed the position of a current block switch
which had been removed from the circuit by ECN L6278 and Work Plan
11326.
Based on these deficiencies, failure to maintain system operating
procedures affected by plant modifications is a further example of
violation 327, 328/85-46-04.
c.
The inspectors selected the same sis at Sequoyah that were found
deficient at the Watts Bar facility during SI review inspections. The
inspection findings at Watts Bar are presented in NRC Inspection
Reports 50-390/84-73, 50-390/85-21, 50-390/85-32, and 50-390/85-51.
The inspectors reviewed seven sis to determine if the deficiencies
identified at Watts Bar existed at Sequoyah.
The sis reviewed were:
SI-3, SI-9, SI-12, SI-40, SI-128, SI-129, and 51-144.1.
Based on the
review of these sis, the inspector determined that the Watts Bar SI
deficiencies were either corrected or did not exist at Sequoyah, with
the exception of SI-12 and SI-144.1.
SI-12 provides instructions for Emergency Core Cooling Systems valve
alignment verification per the surveillance requirements of TS 4.5.2.
This SI did not specify verification of valve position for the two
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automatic flow path valves, LCV-62-132 and LCV-62-133, located at the
outlet of the volume control tank.
The inspector discussed this item
with the licensee and determined that the subject valves are verified
for position by SI-3 during the check of system boration paths.
Furthermore, these valves close upon an ECCS actuation signal.
The
inspector had no further questions.
SI-144.1 controls testing of the Control Room Emergency Ventilation
(CREV) Automatic Actuation feature.
The test objective for this SI is
to verify that on a safety injection signal (SIS), the control room
ventilation system automatically divert air inlet flow through the HEPA
filters and a charcoal absorber bank.51-144.2 requires the same type
of verification by a radiation detector test.
These surveillance
tests must be performed at least once per 18 months as required by
TS 4.7.7.e.2.
Per FSAR Section 9.4, control room isolation occurs
automatically upon actuation of SIS, indication of high radiation, and
either high temperature, chlorine, or smoke concentrations in the
outside air supply to the control building.
Upon actuation, the
control room emergency air cleanup fans will operate in a recirculation
mode through the HEPA filters and charcoal absorbers.
The inspector
found no TS requirement to test the CREV automatic actuation on signals
other than SIS and high radiation.
SI-168, Calibration of Control Room
Air Intake Chlorine Detection System and SI-240, Functional Test of
Control Room Air Intake Chlorine Detection System, do not appear to
test the control room isolation feature on high chlorine. As a result,
all the features that are designed to initiate control room isolation
do not appear to be tested.
Further inspection to ascertain if these
features are tested by the licensee is an Inspector Followup Item (327,
328/85-46-06).
The inspectors also reviewed IMI-92-PRM-CAL, Nuclear Instrumentation
Channel Calibration, and verified that the procedure calls for
independent verification during removal and replacement of instrument
power fuses.
7.
NUREG 1154 (Davis-Besse Event Review)
In response to the NRC findings of the June 9, 1985, Davis-Besse event the
licensee assigned a task team to evaluate the NRC Generic Letter 85-13,
which transmitted NUREG-1154, and an INP0 report entitled "The Operational
Performance of Auxiliary Feedwater (AFW) Systems in U.S. PWRs 1980-1984".
The inspectors reviewed TVA's evaluation of the two documents for the
Sequoyah Nuclear Plant.
TVA's evaluation addressed the significance of the
Davis-Besse loss of main and auxiliary feedwater event with respect to
Sequoyah.
The INP0 report was utilized by TVA to review the Sequoyah AFW
system for problems that have been experienced by other utilities.
The
following nine major topics were evaluated from the Davis-Besse Event:
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a.
Interaction of Plant Security Features and Operator Actions
The inspectors determined that the interaction of plant security
features and operator action problems which occurred at Davis-Besse
would not have occurred at Sequoyah.
At Davis-Besse, the equipment
operators were dispatched to manually open valves and operate the
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turbine-driven AFW pumps in which they had to cope with chained and
padlocked accesses to the pump rooms as well as padlocked manual
handwheels on valves.
For manual control at Sequoyah, the operators
only have to deal with normal card reader doors.
Guards are available
in the vicinity with keys to open doors in the event of failure of the
card readers.
None of Sequoyah's AFW valves or other components are
located in locked high radiation areas, so accesses to the AFW valves
are not required to be locked,
b.
Availability of Shift Technical Advisors (STA)
!
An inspector toured the control room for the purpose of observing the
designated work area and availability of the Shift Technical Advisor
(STA).
The Sequoyah STAS have a desk and file space in the main
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control room (MCR), and are generally confined to this area.
The STA
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may leave the MCR to perform his duties provided he can return within
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ten minutes.
The inspector determined that these conditions would
assure that the STA would be available for utilization during an
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operational event such as the Davis-Besse event.
c.
Reliability of the AFW Containment Isolation Valves and Other Safety
Related Valves
Unlike Davis-Besse, Sequoyah's AFW System does not have any motor-
operated (M0) containment isolation valves.
Sequoyah has experienced
reliability problems with other M0V's in the AFW system and failure of
the main FW isolation valves have occurred due to improper limit switch
settings.
The licensee is implementing increased MOV maintenance, and
the Motor-operated Valve and Test System (M0 VATS) is being used.
The inspector observed an operator training session conducted locally
at the Unit 1 Turbine Driven Auxiliary Feedwater Pump.
The licensee
instructor adequately covered:
problems experienced by operators
during the Davis-Besse event, resetting and local operation of the
Turbine Trip and Throttle Valve (TTV), and local operation of the AFW
Steam Generator Level Control Valves. The inspector found that a
laminated sign had been installed near the TTV with a drawing of
the TTV and instructions for local resetting of the TTV following a
mechanical overspeed trip. Discussions held with management indicate
,
that all operators will receive training of a similar nature prior to
startup of either unit.
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The inspector examined the operator requalification training records
and noted that the program contains a requirement for annual simulator
training on a complete loss of feedwater event (normal and emergency).
The records were adequate to demonstrate that the training is being
performed.
d.
Reliability of AFW Pumps
The reliability of AFW pump turbines is not as critical at Sequoyah
as Davis-Besse because of two 100 percent capacity motor-driven AFW
pumps. The AFW reliability is being further improved by the licensee's
implementation of enhancements in response to an INP0 finding.
e.
Reliability of Power Operated Relief Valves (PORV)
Sequoyah surveillance programs provide some assurance of operational
readiness of the Power Operated Relief Valves (PORV).
However, it does
not provide reliability data for repeated openings and closings under
actual slow conditions, when failures have been known to occur.
The
licensee does not support the NUREG-1154 suggested automatic block
valve closure as a potential remedy for PORV failures.
The use of
Automatic block valve closure for isolation of PORV could result in the
use of the code safeties as a pressure relief path. The code safeties,
which have a history of failure to reset could then be subject to the
same multiple openings as the PORV and cannot be isolated,
f.
Adequacy of control room instrumentation
The inspector reviewed control room instrumentation including the
location of the acoustical monitoring instrumentation for detection of
PORV operation / failure.
The acoustical monitoring instrumentation for
both units is located in the common area of the control room, approxi-
mately equal distance from the Unit 1 and Unit 2 controls.
This location will be evaluated by the licensee during the NUREG-0700
control room design review.
The controls, display and location of the
remainder of the control room instrumentation appeared to be accept-
able.
g.
Adequacy of plant procedures
This item was not assessed during this inspection.
h.
Adequacy of safety system testing
The adequacy of safety system testing was assessed from the AFW system
post modification standpoint discussed paragraphs 8.e. and 8.i. of this
report.
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1.
Acceptability of current safety assessment methods
This item was addressed in paragraph 7.c. above regarding operator
training on a complete loss of feedwater event and resetting of the
Turbine Trip and Throttle Valve.
Based on the above reviews, the team concluded that licensee actions in
response to Generic Letter 85-13, combined with their AFW Reliability
Improvement Program, exceeded regulatory requirements.
8.
Design Changes and Modifications
Selected design changes were reviewed to ensure that the submitted and
implemented changes were in accordance with 10 CFR 50.59 requirements and
that licensee technical reviews were adequate. The inspectors verified that
design changes were reviewed and app (roved in accordance with Technical
Specifications and Quality Assurance QA) controls, that post modification
tests were performed when necessary, that adequate licensee record and
review functions were performed, that operating and surveillance procedure
revisions were made and approved in accordance with Technical Specifica-
tions, that operator training programs were revised, that cperator training
occurred prior to system startup for significant design changes to safety
related systens, that as-built drawings were changed to reflect the modifi-
cations, and that the required 10 CFR 50.59 annual report to the NRC
included those modifications audited.
Administrative Instruction, AI-19 (Part IV), Plant Modifications After
Licensing, describes the method for implementing all facility modifications.
Per AI-19 requirements, the Work Plan (WP) package includes such items as
the affected engineering drawings, Field Change Request Engineering Change
Notice (ECN) or Design Change Request (DCR) that authorizes the modifica-
tion, applicable Modification and Addition Instructions (M&Als), appropriate
work permits (e.g., breeching of fire barriers, concrete chipping), material
traceability forms, and post maintenance testing results. The selected Work
Plan packages were reviewed for compliance with the requirements of AI-19
by the inspectors.
The modification packages reviewed were applicable to
changes made in the instrumentation system, reactor coolant system, emer-
gency core cooling system, containment system, and the auxiliary feedwater
system.
The selection of these modification packages was based on a review
of the licensee's annual 10 CFR 50.59 report submittal for 1984, dated
March 15, 1985.
This submittal included a summary of all facility changes
which the inspectors used to select modification packages for review.
In
addition, the inspectors reviewed modification packages that were completed
in 1985.
The following ECNs, DCRs, and Design Modification Work Plan (WP) packages
were reviewed:
a.
ECN L 5600, which included WPs 9598, 9519, and 9518, modified the
activating system for automatic switchover of Residual Heat Removal
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system suction from the Refueling Water Storage Tank to the containment
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sump to improve reliability.
b.
ECN L 6055, which included WP 10766 was established to install cold
over pressure protection (COP) circuitry in the Solid State Protection
System racks.
c.
ECN L 5093, which included WPs 9980, 11378, and 9969 was established to
install drain and block valves for containment isolation valve penetra-
tions to allow local leak rate testing with air.
No post modification
testing was required for this modification. Many of these valves have
exhibited leakage which has affected local leakrate testing results.
d.
ECN L 2780, which included WP 9516, was established to install reactor
shield building penetration sleeves to support Post Accident Sampling
System installation.
e.
ECN L 5342, Post Modification Test (PMT) 53, was conducted on Unit 1 to
test the Auxiliary Feedwater (AFW) System Cavitating Venturis installed
urder WP 10920.
PMT 53 was performed to verify that the venturis would
prevent pump runout, that the piping vibration levels were acceptable,
and that the AFW Pump would deliver 440 gpm at 400 psia S/G pressure
through the AFW bypass level control valve without motor overload.
Test Instruction Deficiency Report DN-2 for Unit 1 was written because
the piping vibration data did not meet the vibration acceptance
criteria of SQN-DC-V-13.13.
The deficiency was dispositioned by
preloading piping hanger 1AFDH-345.
The preload of the hanger reduced
the vibrations to acceptable levels.
For Unit 2, test deficiency DN-3 identified that vibration exceeded the
acceptance criteria in the Y-axis where displacement was 250 mils zero
to peak versus acceptable displacement of 219 mils.
This deficiency
was noted at full flow conditions and less than 100 psig in the steam
generator.
For corrective action the disposition stated that pump
operation above 440 gpm should be limited to reduce the detrimental
effects of downstream vibration to prevent hanger and instrument line
damage.
The adequacy of the design is questionable since the purpose
of the venturi is to protect the AFW pump from runout damage up to a
,
maximum of 650 gpm flow, and the Technical Specification bases require
the pump to provide no less than 440 gpm.
At the time of inspection
insufficient data was obtained to show at what flowrate vibration
levels were acceptable.
This is identified as an Unresolved Item (327,
328/85-46-07) pending further information from the licensee,
f.
ECN L6285, which included WP 11360, was established to replace the
motor operator of component cooling water system isolation valve
2-FCF-70-87 with an environmentally qualified actuator per NUREG-0588.
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g.
ECN L5883, which included WP 11005, was established to replace and
relocate flow and pressure switches at penetration room cooler fans in
order to meet NUREG-0588 requirements.
h.
DCR 775, which included WP 10183, was utilized to replace existing
Solid State Protection System block handswitches (HS-63-135A,135B,
136A, and 136B).
i.
ECN L 5490, which included WP 9360, was utilized to relocate the Unit 2
Terry Turbine control panel due to temperature effects on the panel.
This package control form did not contain signatures to document
completion of drawing revisions, or a signature for review for
Technical Specification impact by an SR0. The package appeared to be a
reconstruction of a lost original work package.
.
Minor discrepancies were identified during the review of Work Plans
described in paragraphs 8.a. , 8.c. , 8.d. and 8.f. of above. These discrep-
ancies included such items as an incomplete nameplate data form, failure to
include material traceability information, lack of signatures, and unavail-
able engineering justification for such items as severing of reinforcing
bars when making a penetration through a shield wall or using TVA standard
hanger configuration for modification requiring installation of additional
valves.
The inspectors noted that the licensee was cognizant of similar
deficiencies prior to this inspection and had made revisions to the
controlling plant modification procedure AI-19 (Part IV).
For example,
"
AI-19 (Part IV), Revision 11 dated August 22, 1985, added instructions
to document material purchased (i.e. material traceability), added the
requirement for the Shift Engineer to make a configuration log entry when
equipment is removed from service due to a modification, and included a
checklist to ensure that the package is complete.
AI-19 (Part IV),
Revision 12, provided, in part, a requirement to verify that all affected
instructions have been revised. Most of the discrepancies identified by the
inspectors were in Work Plan packages completed prior to the implementation
of AI-19 (Part IV), Revisions 11 and 12.
Therefore, the inspectors have
concluded that the licensee has taken positive steps in improving admini-
strative control of modification packages.
The inspectors also reviewed the licensee's program for temporary modifica-
,
tions, lifted leads, and jumpers.
The following deficiencies were
'
identified:
a.
Approximately 200 temporary alterations are currently active for
'
Sequoyah Units 1 and 2.
This number appears to strain the administra-
tive control system effectiveness.
Step 3.1 of AI-9 requires that
where practical, plant management shall initiate a design change
,
request (DCR) or field change request (FCR) in accordance with AI-19 to
eliminate the need for temporary alterations.
Although a management
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action tracking system requires routine review for the purpose of
determining justification for continued need, many temporary altera-
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tions over three years old are still in place.
Discussions held with
licensee employees indicated that the licensee has committed as the
result of an INP0 audit to clear all temporary alterations made prior
to January 1,1984, before startup following completion of Unit 1
cycle 4.
This is identified as an Inspector Followup Item (327,
328/85-46-08).
b.
No adequate system appears to exist to ensure that post modification
testing is accomplished during restoration of temporary modifications
that do not result in permanent modifications. This has been corrected
for recent temporary alterations, but not addressed for older altera-
tions.
Revision 19 of AI-9 requires that retesting requirements be
identified on the Temporary Alteration Control Form, but the inspector
was unable to determine if long term temporary modifications are covered
by this requirement.
This is identified as an Unresolved Item (327,
328/85-46-09) pending further review of the licensee's program.
9.
Operating Experience Review
The inspectors review of the Nuclear Operations Experience Feedback Program
consisted of a review of Standard Practice SQA-26 and training documents,
and discussions with licensee personnel.
Additionally, Watts Bar Nuclear
Plant's Standard Practice WB6.3.13, Nuclear Operations Experience Review
procedure, was used for comparison.
The inspectors found that some duplication existed in the routing of lessons
learned materials to different sections.
The inspectors reviewed the
modifications performed during Units 1 and 2, cycle 2 refueling outages.
Selected modifications which affected plant operation from the control room
were traced through the training process to ensure that the operations staff
was trained prior to plant startup.
For the cases reviewed, appropriate
training was provided prior to plant startup.
Implementation of the
operating experience feedback program was considered above average by the
team.
10. Westinghouse Setpoint Methodology Verification
The Westinghouse Setpoint Methodology (WSM) for the Sequoyah Nuclear Plant
(SQN) established the appropriate margin between the actual Technical
Specification setpoints used for reactor protection system instrumentation
and the setpoints required to meet the Technical Specification safety
limits.
The margin is calculated by conservatively estimating the errors
.
associated with the reactor protection system instrumentation and actuation
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of the protection equipment.
One of the sources of error evaluated was the
!
accuracy of the Measuring and Test Equipment (M&TE) used to calibrate the
reactor protection system instrumentation.
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On April 15-19, 1985, an NRC inspection at Watts Bar Nuclear Plant (WBN)
identified that certain inconsistencies existed between the calibration
accuracy of the M&TE used to calibrate Solid State Protection System (SSPS)
equipment and the accuracy of the M&TE assumed in the WSM. These inconsis-
tencies were such that the safety margins for at least two parameters
!
at Watts Bar (WBN), including containment pressure, were in doubt.
The
licensee's review of this discrepancy identified that Sequoyah Nuclear Plant
was potentially affected.
Information on the inconsistencies between the
4
WSM and the calibration M&TE used at WBN was provided to the SQN staff at a
meeting with SQN, WBN, and Westinghouse on May 7, 1985.
a.
Accuracy of Measuring and Test Equipment (M&TE)
.
The incorporation of the WSM into the calibration procedures for the
SQN Solid State Protection System (SSPS) was evaluated.
The WSM
'
assumed that the M&TE had an accuracy of ten times that of the equip-
ment being calibrated.
The WSM referenced a Scientific Apparatus
Manufacturers Association (SAMA) document entitled " Process Measurement
and Control Terminology", which described the required M&TE accuracy.
The incorporation of this M&TE accuracy standard allowed the enginee-
ring calculation of inputed error to the sensor calibration accuracy to
be estimated by Westinghouse.
(The actual values of the different
i
error categories and the error categories are themselves proprietary
data and will not be discussed in this report.)
Setpoints based on the WSM were incorporated into the SQN surveillance
and calibration programs.
Several pieces of M&TE used at SQN do
not achieve the ten to one accuracy requirement assumed in the WSM.
Examples of this equipment include instruments used to provide current
inputs such as the Fluke 8600, Keithly 197 and 175, and instruments
used to provide pneumatic inputs such as the Heise 711B and Ashcroft
Digigage.
These pieces of M&TE are used at SQN to calibrate and
functionally test the SSPS instrumentation.
Technical Specifications (TS) require that written procedures shall be
established, implemented, and maintained covering TS surveillance and
2
test activities or safety related equipment.
Instrument Maintenance
Instruction IMI-99, Reactor Protection System, was established to
implement these requirements for the calibration and functional testing
of the Solid State Protection System. TS 6.5.1.6 states that the Plant
Operations Review Committee (PORC) shall be responsible for the review
of all TS required procedures and changes thereto.
'
The calibration procedures of IMI-99 were inadequately established
since they did not reflect the assumptions of the methodology study
and did not justify the technical adequacy of the deviation from the
methodology. This is a further example of violation 327, 328/85-46-04.
Other calibration and functional testing procedcres in addition to
IMI-99 may be affected by the failure to incorporate this requirement.
The licensee has committed to identify and correct these procedures.
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b.
Calibration of Containment Pressure Transmitters
The SQN containment pressure transmitters (Barton 764) were previously
removed from Watts Bar Nuclear Plant (WNP) and sent to SQN for replace-
ment of two non-environmentally qualified Foxboro transmitters.
The
Barton transmitters were installed under Work Plan 11554, which was
approved by PORC on March 30, 1985, and completed on April 3,1985.
After the May 7,1985 licensee methodology meeting, a contract with
Westinghouse was established for Watts Bar to determine the effect of
the incorporation of the actual M&TE accuracy on the calibration of
reactor protection system instrumentation to meet the WBN safety limit
margins.
Preliminary calculations, received by WBN and SQN about
July 3,
1985, indicated that the containment pressure instrument
calibration would result in values that were outside both the Technical
Specification setpoint and the Technical Specification safety limits
when the reduced accuracy of the M&TE was included.
Informal calculations were performed by the SQN compliance staff about
July 8, 1985, which incorporated actual observed values for other
parameters, including setpoint drift, rather than the conservative
values assumed in the WSM. These calculations demonstrated that, based
on the actual historical error values for certain parameters at SQN,
including the M&TE, the setpoint was within the safety limit.
Based on this calculation, the licensee concluded that there was no
engineering concern; however, the licensee failed to recognize and
promptly evaluate the potential failure to meet the Technical Specifi-
cation limits based on the potential error of reactor protection
instrumentation as determined by the design basis document,
i.e., the
WSM.
In addition, the calculations made were informal and reviewed and
formally approved by only one level of plant management.
During this
informal review, the licensee also determined that the original WSM for
SQN had a negative safety margin for containment pressure. This is an
inspector followup item (327, 328/85-46-11).
Technical Specifications require that the Plant Operations Review
Committee (PORC) to review unit operations to detect potential nuclear
safety hazards and to investigate all violations of the Technical
Specifications.
A formal PORC review was not performed after addi-
tional information was received by the licensee, including PORC
members, about July 3,1985, which indicated that the calibration of
the Barton containment transmitters could be outside the technical
specification safety limits.
The licensee continued to operate both
units at full power until late August 1985 without formally reviewing
this potential nuclear safety hazard.
The safety significance of the
overall setpoint methodology issue also was not formally reviewed and
resolved by PORC.
Failure to conduct required PORC reviews constitutes
a violation (327, 328/85-46-10).
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c.
Licensee Actions to Evaluate M&TE Accuracy
SQN established a contract with Westinghouse in September 1985 to
determine if safety limits were exceeded based on the actual accuracy
1
The licensee expects to have preliminary results
j
for the following three areas in January 1986:
Nuclear Instrumentation System RCS Delta Temperature and Average
Temperature M&TE accuracy ratios
Transmitter and rack M&TE accuracy ratios
Containment Pressure Transmitters accuracy ratios
-
Until the results of this evaluation are available, adequacy of the
current reactor protection as-left setpoints is an Unresolved Item
(327,328/85-46-12).
In summary, throughout this methodology issue, the inspection found that SQN
!
management failed to take positive actions to establish that safety limit
'
margins and setpoints met license requirements despite the known Watts Bar
deficiencies.
11.
Reactor Trip Reduction Program
4 .
The inspector reviewed Sequoyah's Reactor Trip Reduction Program.
The
licensee's program consisted of an evaluation of the areas identified in
.
INP0's " Scram Reduction Practices", INP0 85-011. This evaluation was issued
j
in a November 21, 1985 report on scram reduction practices at Sequoyah. The
report addressed in detail each of the INP0 items and identified which were
being implemented and which were standard practice.
!
The licensee identified 27 trips which have occurred since January 1, 1984
!
on Sequoyah Units 1 and 2 in a transmittal letter stating their actions to
meet 10 CFR 50.54(f) commitments. The 27 trips were placed in one following
four categories.
!
Equipment Malfunctions or Failures
13 trips
i
Manual Feedwater Control of Steam Generator (S/G)
8 trips
!.
Personnel Error
5 trips
,
Inexperience with Auto-Bypass Controller
1 trip
i.
for S/G Feedwater Bypass Regulating Valve
!
The root causes of the 13 trips were identified and long term corrective
actions taken consisting of preventative maintenance, design reviews and
posting of warning signs to prevent reoccurrence for five trips.
No long
term corrective action was felt appropriate for the remaining eight trips.
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The licensee preventative maintenance program consisted of:
Critical plant equipment which can cause scrams is inspected and tested
during each refueling outage.
Vendor simulators are used for testing systems.
Preventative maintenance on important equipment is minimized while
plant is operating.
I&C technicians verify that control systems are functioning properly by
stroking components through their full range.
Major equipment performance is monitored so anticipatory corrective
action can be taken prior to a scram.
I
A design change to install automatic control of feedwater bypass regulating
valves was installed to reduce the trips which occurred from manual control.
Additional feedwater system modifications were made as a result of the
Davis-Besse event which will improve the AFW system reliability.
The licensee is implementing additional training to reduce personal errors.
I&C technicians receive a half day of systems training per week as part
of the continuing training programs.
Simulator training is provided for I&C technicians, engineers, and
certain maintenance personnel based on availability of simulator.
Newly hired technicians must complete a certification program that
includes procedures, policies, system training and practical factors.
Certification must be completed satisfactorily prior to performing
unassisted testing.
On-the-job training is conducted by a foreman as part of the training -
i
qualification process.
Vendor training programs are used for critical plant equipment (e.g.,
EAC, governors, motor operated valves).
Operations personnel receive training on plant modifications prior to
placing new equipment in service.
,
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Trainees, including available auxiliary operators, observe and in some
i
cases, receive hands-on experience during the plant evolutions, such as
start-up, synchronization and shutdown in the control room.
Operations personnel are given addition in-depth training on balance of
plant equipment.
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Emphasis is placed on promoting operators up through the ranks from
entry-level positions.
The licensee has also implemented the following practices to reduce plant
trips.
A system engineer is assigned for each plant system.
His responsi-
bilities include the following:
reviewing and trending surveillance test results
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recommending preventative maintenance
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coordinating all design changes
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writing procedures and design changes
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reviewing all maintenance on the system, conducting
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post-maintenance testing and assisting in troubleshooting
The Shift Technical Advisors perform a comprehensive post-trip review
to determine the root cause and the correction of the cause for each
The Shift Supervisor and Shift Engineer perform a joint review after a
scram and an unusual occurrence report is prepared.
A committee of
operations, maintenance, engineering is convened to investigate the
event.
The group reviews data and interviews personnel to determine
the causes of all failures or unusual occurrences for the implementa-
tion of corrective actions.
Plant startup does not commence until all reviews are complete.
The
superintendent or Assistant Superintendent must give the approval to
restart the plant.
A historical data base is maintained to allow analysis and trending by
scram cause codes.
,
The licensee is a member of the Westinghouse Owners Group which has a
'
program for investigating each scram.
Since the majority of scrams are caused by problems in the Balance-
!
of-Plant (B0P) systems, a licensee procedure requires that the same
case is exercised in surveillance, maintenance, operation and
engineering of B0P systems as is in the NSSS systems.
The licensae has implemented numerous other procedure changes,
personnel training and equipment modifications not addressed in this
report.
The licensee was also pursuing improved reliability and trip reductions by
other programs, such as the task force identified AFW system action items
discussed in the Davis-Besse section of this report.
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The actions being taken by the licensee indicated an adequate effort to meet
the 10 CFR 50.54(f) commitments made in their letter dated November 1,1985,
and to improve plant reliability through trip reduction.
The inspector verified licensee implementation of steps taken to reduce the
number of reactor trips on a sampling basis and held discussions with the
training department and operations personnel on this subject matter.
The
inspector concluded that the licensee has taken positive steps to improve
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plant reliability.
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