ML20245B717
| ML20245B717 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 02/03/1989 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20245B703 | List: |
| References | |
| 50-327-89-01, 50-327-89-1, 50-328-89-01, 50-328-89-1, NUDOCS 8904260238 | |
| Download: ML20245B717 (68) | |
See also: IR 05000327/1989001
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ENCLOSURE 1
INTERIM SALP REPORT
U. S. NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
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NRC INSPECTION REPORT NUMBER i
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50-327/89-01 AND 50-328/89-01
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TENNESSEE VALLEY AUTHORITY (TVA)
SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2
FEBRUARY 4, 1988 - FEBRUARY 3, 1989
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TABLE OF CONTENTS
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I. INTRODUCTION.................................................. -1
A. Licensee Activities..................................... 2
B. Direct inspection and Review Activities................. 5
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II. SUMMARY OF RESULTS........................................... 7
A. Basis Period Summary.................................... 7
! B. Assessment Period Summary.............................. 17
C. 0verview............................................... 18
Ill. CRITERIA.................................................... 19
IV. PERFORMANCE ANALYSIS........................................ 20 .
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A. Plant 0perations....................................... .
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B. Radiological Controls.................................. 27
C. Maintenance / Surveillance............................... 30
D. Emergency Preparedness................................. 39
E. Security............................................... 40
F. Engi.neering/ Technical. Support.......................... 42
G.- Safety Assessment /Quali ty Verification. . . . . . . . . . . . . . . . . ., 48
V. SUPPORTING DATA AND SUMMARIES............................... 54
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A. Investigation Review................................... 54
B. Escalated Enforcement Action........................... 55
C. Management Conferences................................. 55
D. Confirmation of Action Letters......................... 56
E. Review of Licensee Event Reports....................... 57
F. Licensing Activities................................... 57
G. Enforcement Activity................................... 63
H. Re a c t o r T r i p s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
I. E f fl u e nt R el e a s e S umm a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
J. Acronyms............................................... 64
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I. INTRODUCTION
The Systematic Assessment of Licensee Performance (SALP) program is an
integrated NRC staff effort to collect available observations and data on
a periodic basis and to evaluate licensee performance on the basis of this
information. The program is supplemental to normal regulatory prococses
used to ensure compliance with Nuclear Regulatory Commission rules and
regulations. It is intended to be sufficiently diagnostic to provide a
rational basis for allocating Nuclear Regulatory Commission (NRC)
resources and to provide meaningful feedback to the licensee's management
regarding the NRC's assessment of their facility's performance in each
functional area. l
)
The last SALP appraisal period for Sequoyah was for the period l
March 1,1984 through May 31, 1985 with the SALP report being issued on
September 17, 1985. In August 1985, both units were shutdown for Environ- ;
mental Qualification (EQ) verification. In the September 17, 1985 letter j
transmitting the TVA SALP reports, the NRC communicated that significant
programmatic and management deficiencies existed in TVA's nuclear program
and pursuant to 10 CFR 50.54(f), TVA was requested to address these de-
ficiencies prior to the s'tartup of any nuclear unit. TVA responded by
issuing and implementing the Corporate and Sequoyah Nuclear Performance
Plans. NRC evaluation of the performance plan implementation is docu-
mented in NUREG-1232, Volumes 1 and 2, respectively, and NRC inspection
reports. Furtier SALP review was deferred pending restart of Unit 2. By
letter dated May 26, 1988, TVA was notified that the normal SALP evalua-
tion process had recommenced as of February 4,1988.
An NRC SALP Board, composed of the staff member s listed below, met on
flarch 28, 1989, to review the observations and data on performance, and
to assess licensee performance in accordance with Chapter NRC-0516,
" Systematic Assessment of Licensee Performance." The guidance and evalo-
ation criteria are summarized in Section III of this report. The Board's
findings and recommendations were forwarded to the Associate Director for
Special Projects, Office of Nuclear Reactor Regulation, for approval and
issuance.
This report is the NRC's assessment of the licensce's safety performance
at Sequoyah for the period February 4,1988 through February 3,1989.
The SALP Board for Sequoyah was composed of:
B. D. Liaw, Director, TVA Projects Division (TVAPD), Office of
fluclear Reactor Regulation (NRR) (Chairman)
L. J. Watson, Acting Assistant Director for Inspection Programs,
TVAPD, NRR
S. C. Black, Assistant Director for Projects, TVAPD, flRR
R. C. Pierson, Assistant Director for Technical Programs, TVAPD, NRR
D. M. Collins, Chief, Radiological Protection and Emergency
Preparedness Branch, Region II (RII)
A. F. Gibson, Director, Division of Reactor Safety, RII
J. N. Donohew, Senior Project Manager, TVAPD, NRR
K. M. Jenison, Senior Resident Inspector, TVAPD, NRR
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The following staff also attended the Sequoyah SALP Board meeting: ;
J. Brady, TVF D, NRR
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P. Harmon, TVAPD, NRR
G. Hubbard, TVAPD, NRP,
S. Weiss, TVAPD, NRR
B. Zalcman, Technical Assistant, NRR
E. Goodwin, TVAPD, NRR
B. Desai, TVAPD, NRR
K. Landis, RII
R. Borchardt, RII Coordinator, ED0
T. Rotella, TVAPD, NRR
A. Licensee Activities
Both units began the assessment period in shutdown from an extended
outage that began in August 1985. TVA agreed, in 1985, not to
restart the units without receiving NRC approval.
On February 4,1988, Unit 2 received NRC permission to enter Modes 4 I
and 3 (hot shutdown and hot standby) and began the heatup process.
The plant was heated up using reactor coolant pump heat and entered l
Mode 4 on February 6,1988. While in Mode 4, approximately nine i
personnel errors occurred which included inadvertent Main Steam
Isolation Valve (MSIV) closures and feedwater isolations, generation
of a reactor trip signal, and a loss of Volume Control Tank (VCT)
level. None of the events resulting from those personnel errors
represented significant safety concerns of their own accord and
collectively appeared to be typical of what one would expect of a
near term operating plant going through the same evolution.
On February 27,1988, Unit 2 entered Mode 3. While in Mode 3, a
number of events occurred including inadvertent closure of all four
MSIVs, exceeding Technical Specification (TS) surveillance limits for
Reactor Coolant System (RCS) leakage, exceeding RCS cold leg accumu-
lator boron concentration, and two events involving auxilicry
feedwater pump operability and charging pump operability of which the
later involved escalated enforcement. The majority of these events
were personnel related and were responded to by the licensee in an
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adequate manner.
On March 22, 1988, the NRC Commissioners voted to allow Unit 2 to
restart. On March 30, the NRC approved entry into Mode 2 (Startup).
On March s1, prior to actually beginning dilution, the licensee
determined that modifications would be required on one of the three
pressurizer safety valve loop seals, and the restart was delayed.
During resolution of problems with pressurizer loop seals, a tube
leak was identified in the #3 steam generator. On April 7, Unit 2
began a cooldown to Mode 5 (cold shoutdown) to repair the steam
generator tube leak and complete pressurizer loop seal modifications.
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On May' 7', Unit 2 began the heatup process again and entered Mode. 4.
On May 11, Unit 2 entered Mode 3 and on May 12, Unit 2 entered Mode 2.
Control rods were withdrawn and dilution to criticality Began. On
May 13, the reactor achieved criticality, entered Mode 1 (power
operation), and the generator was synchronized with the grid. On May
15, the NRC granted permission to allow operation above 30% power and
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power escalation was resumed. During the power escalation process
several minor events occurred which included the discovery of an
unqualified splice in the circuitry for one of the steam generator
water level indicators.
On May 19, Uni 2 tripped from 73% power due to steam flow / feed flow
mismatch coincident with low-low steam generator level. This situa-
tion occurred due to maintenance being performed concurrently cn two
pieces of equipment which together could cause a reactor trip (one
channel of steam generator level indication to replace the
unqualified splice and the #3 heater drain tank level controller
which resulted in plant oscillations). On May 20, efter corrective
actions for the trip were completed, NRC permission was given to
restart Unit 2.
On May 21,' Unit 2 achieved criticality. entered Mode 1, and was
synchronized with the grid. .
On May 23, Unit 2 tripped from 70% power on low fbs in RCS Loop #4.
This occurred due to a personnel error while performing a surveil-
lance instruction on the loop #4 flow transmitters. Or, May 24, Unit
2 achieved criticality, synchronized with the grid and began power ;
escalation.
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On May 24, while Unit I was in partial drain to plug steam generator
tubes, a loss of decay heat removal occurred due to an cperatcr error ,
in positioning valves while changing the residual heat removal (RHR)
system alignment.
On May 29, 1988, Unit-2 achieved 100% reactor power.
On June 6,1988, Unit 2 tripped from 98% power on stean flow / feed
flow mismatch coincident with low level in #4 steam generator. The .
trip occurred while performing a surveillance on the feedwater l
regulating valves and resulted because a diode was missing in the
block circuit.
On June 8,1988, Unit 2 tripped from T2% power on low-low level in #2
steam generator. The trip was caused by operator error when placing
the feed pump contro'.ler in the automatic position which resulted in i
steam generator level oscillations.
On June 9, 1988, Unit 2 tripped from 20% power on low-low level in 72
steam generator. The trip was caused by transients in feed flow and
steam generator level which were initiated by feedwater heater
isolations.
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'On June 13, 1988, TVA mec with the NRC staff to discuss the root
causes _ for the five reactor trips which had occurred since Unit 2
restarted on May 18, 1988. Corrective actions identified included
l reducing the number of outstanding secondary plant work requests
which could contribute to balance of plant induced reactor trips.
On June.19, 1988, the NRC granted permission t'o restart Unit 2. On
June 30,1988, Unit 2 reached 70% reactor power (holding for core
life extension).
On September 27, 1988, the NRC granted permission ~for Unit I to enter
Mode 4. While in Mode 4, several unanticipated reactor trip signals
were gener M due to personnel errors while performing
surveillance.
On October 20, 1983, Unit 1 entered Mode 3. While in Mode 3, the UHI
membrane was ruptared while putting the system in service due to.
improperly labeleo valves. Equipment problems such as steam
generator safety valve at leakage, pressurizer safety valve seat
, leakage, reactor vessel inner seal leakage, and steam dump packing
leakage were encountered and properly resolved.
On ' November. 6,1988, Unit 1 entered Mode 2 and went critical . On
November 10, 1988, Unit 1 entered Mode 1, the generator was
synchronized with the grid, and power escalation began. Several
personnel errors related to equipment surveillance caused ESF
actuations while in Modes 2 and 1.
On November 18, 1988, Unit 1 tripped from 72% power due to an
electrical ground in the main generator stator. During the forced
outage to repair the generator stator, repairs to leaking steam
generator safety valves and a pressurizer safety valve were also
accomplished. ,
On December 25,1988, Unit 1 achieved criticality, entered Mode 1,
the generator was synchronized with the grid, and power escalation
began.
On December 26,1988, Unit 1 tripped on low-low level in #4 steam
generator. The trip was caused by a series of events that started
with a manual trip of the turbine due to generator seal rubbing.
After the turbine trip, steam generator level was controlled using
manual feedwater control which resulted in a feerwater isolation from
high-high level in #2 steam generator followed by the reactor trip on
low-low level in #4 steam generator.
On December 27,1988, Unit 1 achieved criticality and began power
escalation. On December 30, 1988, Unit I achieved 98% reactor power.
On January 19, 1989, Unit 2 was shutdown to begin the s heduled cycle
3 refueling outage after 210 continuous days of operation.
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B. Direct-Inspection and Review Activities
During the assessment period, routine inspections were performed at
the Sequoyah facility by the NRC. staff. Special inspections were
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conducted as follows.:
- February 4~- June 25, 1988; a series of special inspections.cf
the Unit 2 heatup and restart effort were conducted by the NRC
Sequoyah Restart Task Force. These inspections included control
room observation and reviews of activities associated with the
restart effort. (88-02,88-17,88-20,88-22,88-26,88-28,88-34)
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- February 1-19, 1988; a special inspection was performed to
assess the corrective actions performed by TVA in response to
the findings of the Integrated Design Inspection. (88-13)
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February 8-12, 1988; a special inspection was conducted to
assure that the licensee's corrective action program implementa-
tion adequately dispositioned adverse conditions, including
generic issues. (88-15)
- February 15-19, 1988; a special inspection of the open restart
issues' in the civil engineering area was conducted to determine
that adequate corrective action and resolution had occurred to
support the restart of Unit 2. (88-12)
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- February 29 - March 4, 1988; a special operational readiness
inspection was conducted to assess the adequacy of the
licensee's preparations for Unit 2 restart. (88-16)
- March 14-23, 1988; a special fire protection inspection was
conducted for Unit 2 restart in the area of implementation of
the' requirements of 10 CFR 50 Appendix R, Sections III.G, III.J. l
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III.L, and 111.0 including safe shutdown logic. (88-24)
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June 20 - July 8, 1988; a special Safety System Quality
Evaluation vertical slice review was conducted on the j
Containment Spray System to assess the licensee's Nuclear
Performance Plan implementation for Unit I restart. (88-29)
- July 11-15 and August 23-24, 1988; a special inspection was
conducted to assess the effect of excessive cooldowns following
reactor trips on end-of-life shutdown margin. (88-35)
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' July 25-28, 1988; a special fire protection inspection was
conducted for Unit 1 restart in the area of implementation of
the requirements of 10 CFR 50 Appendix R, Sections III.G, III.J,
III.L, and 111.0 including safe shutdown logic. (88-37)
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August 29 - September 2,1908; a special operational readiness
inspection was conducted to assess the adequacy of the
licensee's preparations for Unit 1 restart. (88-42)
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- September 6-9, 1988; a special inspection was conducted to
assess the licensee's unreviewed safety question determination
program and implementation. (88-43)
- September 25 - November 21, 1988; a series of special inspec-
tions of the Unit I heatup and restart effort were conducted by
the NRC Sequoyah Restart Task Force. These inspections included
control room observation and reviews of activities associated
with the restart effo-t. (88-40,88-46,88-47,88-48,88-49,88-51,
88-52,88-55)
- December 12, 1988 - January 26, 1989; a special ' quality
verification inspection was conducted in the areas of
maintenance, modifications, operations, radwaste processing, and
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correctiveactions.(88-50)
The staff spent more effort on Sequoyah than on any other operating
plant and also expended more effort than 'during the basis period.
Reviews by the staff included TVA's Corporate and Sequoyah Nuclear
Performance Plan (NPP) programs; the Employee Concern Task Group
(ECTG) element reports; sixty-five amendments to the Unit 1 and 2
Technical Specifications including an exigent amendment, an emergency
amendment, and a waiver of compliance; and four exemptions. The NPP
reviews were documented in the NRC Safety Evaluation Report
NUREG-1232 Volume 1 and 2 and its supplement, and included reviews in
the major areas of adequacy of design, special programs, restart
readiness, employee concerns, and allegations. The areas of adecuacy
of design, special programs, and restart readiness were further
. broken down as follows:
Adequacy of Design
1. Plant Modification and Design Control
2. Design Baseline Verification Program
3. Design Calculations Program
4. Alternately Analyzed Piping and Supports
5. Cable Tray Supports
6. Concrete Quality
7. Miscellaneous Civil Engineering Calculations
Special Programs
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1. Fire Protection i
2. Environmental Qualification of Electrical Equipment
Important to Safety
3. Piece Part Qualification (Procurement)
4. Sensing Line Issues
5. Welding .
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6. Containment Isolation
7. Contair, ment Coatings l
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'8. Moderate-Energy Line Breaks
9.- ECCS Water Loss Outside Crane Wall / Air Return Fan
0perability
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10. Platform Thermal Growth
11. Pipe Wall Thinning Assessment
12. Cable Installation
13. Fuse Replacement
Restart Readiness
1. Operational Readiness
2. Management
3. Quality Assurance
4. Operating Experience Improvement
5. Post-Modification Testing
6. Surveillance Instruction Review
7. Operability "Look Back"
8. Maintenance
Restart Test Program !
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10. Training
11. Security
1~2 . Emergency Preparedness
13. Radiological Controls
14. Restart Activities List
II. . SUMMARY OF RESULTS- ,
' A' comparison of the present SALP ratings to the previous SALP ratings cf 4
years ago (1984 to 1985) would be of little benefit in determining the
current trend of the licensee. In order to evaluate the current trend cf
the licensee from the reassessment period to the assessment period, an
additional summary is provided below of the NRC staff evaluation for the
period from January 1,1987 until the start of the assessment period
(February 4,1988) to be used as a basis for comparison.
The' NRC established an Office of Special Projects (0SP) in February 1987
to address the particularly complex regulatory problems of TVA and one other
utility. Part of the OSP goal was to assess whether identified problems
to the licensee were on a path to an acceptable solution, and where not,
to identify acceptable solutions necessary to enable the staff to complete
its licensing reviews of these facilities, consistent with the NRC's
statutory mandate to protect the health and safety of the public.
A. Basis Period Summary (January 1,1987 - February 3,1988)
1. Plant Operations
During the entire basis period both units were in the shutdown
mode. Weaknesses were identified in the adequacy of Abnormal
and Emergency Operating procedures, emergency contingency action
procedures, compensatory operator actions, configuration
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control, the clearance process, investigation and resolution of i
event related issues, . involvement of first line and upper level j
management in the day-to-day operation of the plant, and control j
and authority over plant activiMes impacting schedule. Some !
deportability / operability determinatices were classified as
unknown while awaiting Division of Nut ear
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review which was not always t;mely or responsive. In addition,
there was a reluctance by the licensee to report items that they
felt were minor. As a result, several events were nct properly
classified and repneted. Material condition, drawing adequacy
and configuration management training were acceptable.
These issues indicated a lack of management attention to and
involvement in the operational aspects of the plant. Control
room operators were burdened with the work control management
function. Their decisions in controlling these activities were
often reversed by management. This resulted in limiting the
amount of time senior reactor operators spent in the plant, a
reduction in the amount of time reactor operators spent
observing control panel indications, and a feeling that
management did not respect their ability to make decisions.
Several management changes occurred during the basis period
which contributed to major improvements.in plant activities. The
new managers included the Deputy Site Director, Plant Manager,
Operations Superintendent, and Corporate Outage / Maintenance
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Managers.
The operations section was adequately staffed to suppnrt piant
operations. ' Control room and plant shif t rotation was increased
to a six shift rotation late in the basis period. Overtime wcs
routinely used to augment normal shift staffing with several
occasions identified where administrative limits were exceeded
without receiving prior plant manager approval. The 1987 i;RC
replacement examinations for licensed operators indicated
satisfactory results (5 out of 5 passed).
Measures were implemented to revise and control primary drawings
in the control room. These drawings were redrawn and
maintained by computer-aided drafting systems which resulted in
improved accuracy and a more timely revision process. System
logic drawings.were removed from the primary drawing list during
1986 because they were not routinely updated and revised as
plant systems were modified.
Procedural compliance by Operations personnel was judged to be
marginally better than the plant staff as a whole. Instances of
procedure deviations and non-compliances occurred at an
unacceptable frequency, and resulted in several reportable
events.
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.The licensee made considerable progress in resolving the several
hundred technical issues encountered after the 1985 shutdown of
both units. Issues that remained to be resolved at the end of
the basis period included the evaluation of containment sump
level transmitters, lower containment coolers, and Senior
Operator manning.
2. Radiological Controls
Inspections conducted during the basis period of the Sequoyah
radiation protection program, indicated that the actions taken
by the licensee, including correction of previous weaknesses in
its program for maintaining exposure as-low-as-reasonably-
achievable (ALARA), were sufficient to support plant restart.
One significant event involved an exothermic reaction during a
radwaste solidification process which caused personnel
contaminations and higher than expected radiation levels.
Considerable organizational changes had taken place in the
Chemistry Group during the period. These revisions assured
close management involvement in maintenance of quality, storage
of radioactive waste, and effluent releases. Close coordination
with the Corporate Chemistry group resulted in resolution of
. technical issues in a timely manner.
The organizations were responsive to NRC initiatives in that
,, open items were being . closed out as the organization prepared
for Unit 2 startup. Staffing had been reviewed, and several new
management personnel were added to the Chemistry Group.
3. Maintenance / Surveillance
During the SALP basis period the Sequoyah maintenance program
experienced numerous weaknesses. These weaknesses were in
procedural compliance, corporate maintenance guidcnce,
maintenance trending, root cause analysis, first line manage-
ment involvement, training for maintenance planners, work
control, maintenance coordination, equipment classification
(Q-list), maintenance history tracking and trending, mainten-
ance procedure adequacy, plant drawing use, the preventive
maintenance program, accountability of maintenance tools and
equipment, post modification testing, quality assurance
involvement with maintenance activities, temporary alterations,
and corrective action. In addition, there were significant
backlogs .in the modifications, temporary modifications, and
maintenance areas. There was significant overlap between those
issues identified by ,the NRC and those issues identified by
TVA's Nuclea.r Manager's Review Group maintenance inspections.
Tracking, trending and scheduling were improved and craft
reviews were implemented which improved the quality of mainten-
ance activities. Areas that did not demonstrate active direction
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during the basis period were the maintenance instruction
enhancement project which was resolved during the SALP
assessment period,' and composite maintenance crews which were
identified by the Nuclear Maintenance Review Grcup (NMRG) as
having implementation problems but were not acted upon by TVA
. management. Institute for Nuclear Power Operations (INP0)
accreditation of the training for nine previously selected
maintenance craft areas was received during the SALP basis
period.
The NRC identified significant problems in the area of procure-
ment of safety-related parts and equipment at Sequoyah and was '
considering escalated enforcement action. Based on the NRC
findings, TVA in general and Sequoyah in particular initiated an
extensive Replacement Items Program (RIP) to ensure that
appropriate parts and equipment were installed in the plant for
EQ and seismic qualification of equipment prior to the restart
of the Sequoyah units. This included training in repair part
and procurement control which was considered one of the causes .
of the problem. Based on the shutdown plant enforcement policy I
and successful implementation prior to unit restart, these
issues were given discretionary enforcement. The program also
established controls to ensure that future procurement of
safety-related equipment met the appropriate requirements.
Sequoyah was completing the documentation and field work for ,
their EQ program. Sequoyah was found to have an excellent EQ
program which had proper management attention ard proposed sound
technical resolutions as problems arose. TVA management was
found to be knowledgeable of NRC and industry standards and
requirements in this area.
Licensee management recognized that storage of equipment did not
-meet the requirements of American National Standard Institute
(ANSI) 45.2.2 and initiated an improvement program to correct
this problem. The' equipment storage upgrade program initiated
by licensee management was adequate and well implemented. The
implementation included a computerized tracking system to ,
identify the exact location of each part, and well organized, i
clearly marked storage areas that met the ANSI 45.2.2 storage
class requirements, even at remote on-site locations. At the
close of the SALP tasis period safety related component storage
was in excellent condition, as a result of several energetic
knowledgeable managers who were personally involved in the
resolution of this industry wide issue.
As a resul t of significant NRC concerns with surveillance
instruction inadequacies which were under consideration for
escalated enforcement, the licensee established a surveillance
instruction review team to compare existing surveillance i
instructions to TS surveillance requirements. This review 1
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effort identified.a significant number of additiona! issues that
resulted in approximately 15 Licensee Event Reports (LERs) being
written. A number of significant revisions and management
changes were inade to' the surveillance instruction review and
update program to achieve technically adequate surveillance
instructions that met the surveillance requirements. Management
involvement in the final effort was aggressive and included an
independent validation process which wcs particularly well
l managed and ensured that the surveillance instructions produced
were of high quality and technically adequate. Based on the
shutdown plant enforcement policy and implementation of an
acceptable surveillance program prior to restart, these issues
were given discretionary enforcement. i
The licensee established a Nuclear Performance Plan Restart Test
Program in order to ensure the operability of scfety related ,
equipment which had been modified. A review matrix of component. i
functions and previous",y performed surveillance was established '
to ensure the testing of functions that had not been tested.
This program was considered adequately staffed with trained
individuals and was determined to be acceptable. Only the
closure of Mode 3 and 2 related items was deferred into the SALP
period.
A problem was identified in the Inservice Test (IST) valve test
program in that essentially all category A and B valves were
~ included in one Surveillance Instruction (SI) and scheduling was
. based on the issue date for the SI package, not the test date
for individual valves in the package. The test dates for
individual valves were not controlled resulting in a number of
valves exceeding their. test frequency. ,
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Procedural adherence was a weakness which contributed to several !'
events and enforcement actions and indicated a lack of manage-
ment involvement in and attention to this area. In addition,
corrective actions were not effective in reducing the results of
this weakness until well into the SALP assessment period.
Conduct of testing was identified as an area of weakness during !
the activities leading up to the restart of Unit 2. The
licensee took strong corrective action with the issuance of
special conduct of testing administrative controls which
resulted in a significant improvement in plant operations.
The effectiveness of the short term layup of the steam and power
conversion system (the secondary water system) was adversely
affected due to uncertainties in the startup schedule. The
uncertainties were directly related, to the inability of
management to control restart activity schedules. Continuous
maintenance and modifications of systems created a condition
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where the desired controls did not in some cases maintain the
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parameters for minimizing corrosion and degradation of the
car1 steel systems. The licensee was responsive to NRC
cor ms expressed during inspections and to NRC information
not a. Actions were taken to enhance the pro,tection of
systems .during the extended short term layup.
Organizational changes in the water chemistry program were a
strengthening factor for water chemistry control. Qualifica-
tions of the chemistry management and staff were adequate with a
sufficient number of chemists and analysts to maintain chemistry
control. Other elements of the water chemistry progran
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(procedures, training, and equipment) were maintained at a
sufficient level to achieve chemistry control during plant
startup.
During the basis period the licensee made progress in changing
its maintenance philosophy from reactive to preventive and was
trying to reinforce procedural compliance.
4. Emeroency Preparedness
The Emergency Preparedness program was adequately maintained
during the basis period. Two routine inspections and an
emergency exercise indicated the. licensee was maintaining an
effective emergency preparedness program. Licensee management
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attention to the program was adequate The two violations
identified during the rcutine inspections oddressed an
inadequacy in the training for licensed operators and a failure
to conduct required monthly concunications checks fcr three
months.
5. Security
Four routine' security inspections, one material control
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inspection and two special inspections relative to Fitness for
Duty and pre-employment screening were conducted. Two
violations were tited for failure to adequately post a
compensatory officer, and for failure to maintain a bullet-
resistant barrier. The Fitness for Duty program was judged
adequate with both a few noteable strengths and one significant
weakness. The NRC exercised discretionary enforcement in not
issuing a violation regarding numerous pre-employment screening
errors due to the significant corrective action initiated and
that the program was examined and determined acceptable prior to
plant startup. During this period the licensee, although
non-operational, did not reduce its security program nor did it
"de\ italize" any of its security areas. The NRC inspection
proc, ram also included various allegations, Employee Concerns and
the licensee's Regulatory Improvement Plan.
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A licensee Quality Assurance -Audit (QSS-A87-0010) was
performed and no regulatory issues were raised. With respect to
Safeguards Event Reports, there were four relative to expired !
7_
badges not being voided and various visitor / escort deficiencies.
n
Of the 225 security incident reports per 10 CFR 73.71
requirements, the vast majority (nearly 95%) resulted from the
failure of equipment (hardware and systems) and not human
errors.
Midway through this period, the licensee reorganized its
security organization which resulted in security officers
working for and being accountable to ,the Corporate Nuclear
Security Support Branch, as oppose to the previous multi-
management-level structure criticized in prior SALP Reports. A
new site Security Manager was assigned to the site in July 1987.
L The extended' use of numerous compensatory iaeasures neeGd !
because of failed equipment remained the. most significant l
regulatory issue throughout this period. ticwever, the licensee
was judged as adequately meeting requirements and providing
security for the facility. -
6. Engineering / Technical Support
The licensee's performance in the engineering / technical support
area was greatly affected by the many changes which were being
experienced by the engineering / technical support staff. Early
in the baseline perind, the licensee was trying to obtain a
clear definition of the scope of effort required to resolve many
technical and design issues which had been identified through
licensee sponsored evaluations and audits and NRC inspections;
however, the engineering and technical support staff was
hampered by changes in organization structures and changes in
key personnel as well as major changes to the internal
engineering procedures.
While the above changes hampered early baseline period
performance in engineering / technical support, the licensee had
- established many special programs to address and resolve
previously identified issues as well as new issues identified
durug the baseline period (e.g. discrepancies identified during
the NRC integrated design inspectn (IDI)). Some of the issues
for which special programs had two established included EQ of
safety-related electrical equipt ~t; design and configuration
control (design baseline verification program); design
calculations review - electrical, mechanical, nuclear, and
civil; electrical issues; instrument sense line issues;
component and piece part qualification; Appendix R; and restart
testing.
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The licensee performance in the - engineering / technical support
area was satisfactory for some of the programs; however, other
programs. were satisfactory only after corrections were made
based on NRC input. Examples of programs where the licensee's
. performance was satisfactory and the program implementation was
considered acceptable were: EQ; civil calculations; cable tray
supports; technical drawings; Design Baseline and Verification
Program (DBVP); and heat code traceability.
Examples of programs where program implementation was initially
considered inadequate included: component and piece part
qualification (inadequate seismic qualification and dedication
of commerciti grade parts for use in safety .c ted equipment);
pipe hangers and supports (inacecuate ~ caic id tions and
documentation to demonstrate that installed pipe hangers and
supports met plant design criteria); and instrument sense lines
and instrumentation accuracy calculations (lack of sufficient
conservatism). While the licensee's implemen :ation of some
programs was initially judged to be unsatisfact'ry or inadequate
relative to engineering / technical support, once problems or
concerns were identified, the licensee satisfactorily resolved
the problems and completed the programs.
7. Safety Assessment /Qu'ality Verification
For the basis period, there was an extensive review effort on
Sequoyah. The review effort included the following significant
items: .
1. review of the Corporate Nuclear Performance Plan was
completed and NUREG-1232, Volume 1 was issued;
2. most of the review of the Sequoyah Nuclear Performance Plan
was completed;
3. most of the Employee Concerns Task Group (ECTG) element
reports on Sequoyah were reviewed;
4. thirty amendments to the Units 1 and 2 TS were issued; and
5. twenty-one meetings were held with TVA on various technical
issues.
Overall, the work submitted by TVA was reasonably good. The
submittals generally showed evidence of prior planning by
management. An understanding of the technical issues was
generally !pparent. The resolutions of issues were generally
viable, timely, sound and well thought out with conservatism
exhibited by the licensee's approach. This was generally true
in the basis period except for the issues of cable testing and ;
the transition of senior nuclear power management from contract
employees to permanent employees.
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-TheLissue of. cable testing which included the issue of-test ing
10'CFR 50.49 silicone rubber insulated cable which was inside
!" containment ; was protracted and- drawn out. .The issue' was -
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discussed tnroughout the basis period and was not resolved for
'1 Unit 1 until the! staff letter of- May 25,.1988 in the . rating
period. ' Die resolution of this issue was not timely and -the
technical issues were not well thought out.
2 .
E The TVA response to the staff's concer.:s on the transition of
,
TVA senior nuclear management was acceptable and the_ safety
- evaluation on the TVA's Corporate Nuclear Performance Plen was
issued on July 28, 1987; but, TVA was not responsive to the
issues raised ~ by the staff pertaining to the transition from
l Jcontract managers to.TVA permanent managers. As a result, the-
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staff was compelled to request TVA to notify the staff 30 days-
in advance 'of any permanent changes of the senior nuclear
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managers.
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6 . In Janaery 1987, the NRC approved (for a period of two years)
.TVA's Quality Assurance Topical Report', TVA-TR75-1A, Revision 9,
which was; developed to resolve past problems relating to the
inability of management. to take prompt effective corrective
action to. prevent recurrence of problems. The past problems
were under consideration for escalated enforcement at the start
of the basis period. During the basis period, Sequoyah began
implementing the.new topical requirements which involved hiring
c the additional- staff required,' training them to appropriately
implement 1the program, and then monitoring the implementation to
ensure thatithe desired results were achieved. During this
transition period Sequoyah experienced significant implementa-
tion problems especially with the conditions adverse to quality
'(CAQR) program which was the subject of several TVA audits and
.NRC inspections. The TVA audits concluded taat the root cause
of the failure.of theLprogram to not fully process any signif-
icant CAQRs'was due to a lack of line management and Quality
Assurance (QA) management involvement and attention. This was
the same reason the previous corrective action program hadn't
been effective. Sequoyah responded by deeply involving upper
level managers in the corrective action program implementation.
While . problems still existed in the QA program implementation,
the staff concluded that the program began moving in a positive
direction toward the end of the basis period after upper level ;
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management involvement had significantly increased. Based on '
the shutdown plant enforcement policy and implementation of an
acceptable corrective action program prior to restart, the past
problems were given' discretionary enforcement.
.
The three ' safety committees which functioned during the basis f
period [ Plant Operations Review Committee (PORC), Nuclear Safety l
Review Board (NSRB), Independent Safety Engineering Group {
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(ISEG)] went through a change process due to TS changes and >
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charter reviews, which were for the most part a result of NRC
initiatives. PORC was initially ineffective, however, improve-
ment-was observed near the end of the basis. period due to both
the qualified reviewer TS change and a new plant manager. The
NSRB and ISEG did not independently identify issues which
produced substantive changes to the site.
During the basis period, 88 LERs were issued of which 26 were
classi fied as significant. These resulted primarily from the
design reviews which TVA had initiated. Some LERs were unclear
with respect to the root cause determination of events or
differed from the staff determinations. The licensee esta-
blished an ISEG audit, identified similar concerns, and was
implementing ISEG and NRC recommendations at the end of the
basis period. j
Both the Special Employee Concerns Task Group (ECTG) and the new !
Employee Concerns Program (ECP) were in existence during the
basis period. The ECTG was working on resolution of the
concerns which it received in the 1985 to early 1986 time frame. q
Numerous revisions to the ECTG reports and their corrective l
actions occurred as a result of NRC review. All employee {
concerns received during the basis period were processed through
the ECP. The NRC identified weaknesses relating to resolution
of generic Lconcerns, administrative issues, and restart
determinations which were.promptly addressed and corrected by
the ECP management. NRC reviews of both programs indicated that
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concerns were being adequately addressed at the end of the basis
period. j
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TVA Nuclear Power corporate management was usually involved in
Sequoyah site activities in an effective manner during the basis
period. There were several management changes at the site which
contributed to major improvements in operation, security and
radiological controls during this period. There were corporate
audits made in the radiological controls and maintenance areas
where actions were taken by corporate management to strengthen
these programs. Although many significant problems in programs
at the site were not being identified by TVA prior to NRC
inspections, usually strong corrective actions from the corporate '
level were taken when it was needed to correct the identified
problems.
For the basis period, corporate management was generally
responsive to NRC initiatives. Responses to NRC were generally
timely and generally sound and thorough. This is shown in the
significant amount of work completed by the staff and TVA in the
basis period.
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The staff conducted an inspection of management effectiveness 1
related to licensing _ activities in the basis period. The
inspection was conducted in key areas of responsibility at both
the plant site and corporate offices. The staff concluded that
corporate management processes in the areas inspected were
functioning adequately.
B. Assessment Period Summary (February 4,1988 - February 3,1989)
Sequoyah has been operated in an overall safe manner during the
assessment period. Management involvement in and attention to the
operations and support of the plant has significantly improved as a
result of the strong leadership exhibited by the new plant a.anager
and new site director.
The plant operations area matured during the assessment period. After
starting the assessment period with five reactor trips, Unit 2 was on
line for 210 continuous days which established a TVA single unit
record. Unit 1 experienced two reactor trips during startup with
full availability for the rest of the assessment period. Strengths
included the procedures upgrade programs, the emphasis on procedural
compliance, and the ownership concept for the operators. Corrective
activs for problems once the root cause was identified were consider-
ed a strength. Weaknesses included operation of the radwaste system;
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root cause analysis in relation to the post-trip cooldown shutdown
margin issues; and the performance of fire watches. Control of plant
activities by the control room operators improved during the latter
half of the assessment period.
The overall. quality and experience level of the health physics staff
is _a program strength, and the licensee's health physics, radwaste,
and chemistry staffing levels are adequate and compare well with
other utilities having facilities of similar s,ize. Management
provides adequate support and is involved in matters related to
radiation protection.
The maintenance / surveillance area also matured during the assessment
period. Strengths included the leadership exhibited by the new main-
tenance superintendent. the establishment of the work control group,
the establishment of a preventive maintenance upgrade program,
implementation of the system and train outage concept for scheduling
maintenance, and implementation of the system of the month review
program. Weaknesses included the large number of personnel errors or
inadequate procedures which resulted in Engineered Safety Feature or
reactor protection system actuations; the inability to produce ;
realistic schedules; and the inability to correct problems associated
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with the feedwater control system. ,
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During a full' participation exercise, the licensee demonstrated :'
that they could satisfactorily respond to an emergency at the
facility. However, weaknesses were noted in that the licensee had on
two' occasions failed to promptly report a Notice of Unusual Event
(NOVE) and also failed to recognize an explosion as requiring entry
into the emergency classification logic during the emergency j
exercise.
In the security area, a high number of hardware equipment inade-
quacies exist. These inadequacies, which are a result of the
security equipment being obsolete, have lead to a continuous depen-
dence on compensatory measures. Corporate support was weak because
of a high turnover rate; however, the licensee has finalized a
reorganization of its Corporate Nuclear Security Service Branch which
has resulted in some improvements. The site management has been
instrumental in dedicating site support to help the security branch
reduce the number of security compensatory measures.
The Engineering / Technical Support ac'tivities did not significantly i
exceed minimum regulatory requirements. While numerous issues were
resolved - during the assessment period, many of the issues were ;
resolved only after considerable NRC input. Support for operations I
of the plant was initially viewed as a weakness but improved late in
the assessment period.
4 ~
In .the Safety Assessment / Quality Verification area, the most
important improvement was in the corrective action program which made
. significant strides during the assessment period. Strengths included
the significant management attention to and involvement in the
corrective action process, the strong leadership provided by the
plant manager and new site director in getting employees to accept 'j
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responsibility for doing quality work, the quality monitoring and
audit program, and the employee concerns program. Weaknesses in-
cluded the 10 CFR 50.59 safety evaluation program and the slipping of
the dates and scope changes for commitments made to the NRC. 3
C. Overview
February 4,1988 - February 3,1989
Functional Area Rating Trend ,
Plant Operations.................... 2 None
Radiological Controls............... 2 None
Maintenance / Surveillance............ 2 .None
Emergency Preparedness.............. 2 None
Security............................ 2 None
Engineering / Technical Support....... 3 Improving
Safety Assessment / '
Quality Veri fica ti on. . . . . . . . . . . . . . 2 None
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III. CRITERIA
Licensee performance is assessed in selected functional areas, depending
on whether the facility is in a construction or operational phase.
Functional areas normally represent areas significant to nuclear safety
and the environment. Some functional areas may not be assessed because of
little or no licensee activities or lack of meaningful observations.
Special areas may be added to highlight significant observations.
The following evaluation criteria were used, as applicable, to assess each
functional area:
1. Assurance of quality, including management involvement and control;
2. Approach to the resolution of technical issues from a safety
standpoint;
3. Responsiveness to NRC initiatives;
4. Enforcement history;
5. Operational and construction events (including response to, analyses
of, reporting of, and corrective actions for);
. 6. Staffing (including management); and
7. Effectiveness of the training and qualification program.
Nowever, the NRC is not limited to these criteria and others may have been
used where appropriate.
On the basis ~ of the NRC assessment, each functional area evaluated is
rated according to three performance categories. The definitions of these
performance categories are as follows:
1. Category 1. Licensee management attention and involvenient are
readily evident and place emphasis on superior performance of nuclear
safety or safeguards activities, with the resulting performance
,
i substantially exceeding regulatory requirements. Licensee resources
are ample and. effectively used so that a high level of plant and i
personnel performance is being achieved. Reduced NRC attention may l
be appropriate.
2. Category 2. Licensee management attention to and involvement i r.
the performance of nuclear safety or safeguards activities is good.
The licensee has attained a level of performance above that needed to ,
meet regulatory requirements. Licensee resources are adequate and j
reasonably allocated so that good plant and personnel performance is 1
being achieved. NRC attention may be maintained at normal levels.
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3. Category 3. Licensee management attention to and involvement in
the performance of nuclear safety or safeguards activities are not
sufficient. The licensee's performance does not significantly exceed
that needed to meet minimal regulatory requirements. Licensee
resources appear to be strained or not effectively used. NRC atten-
tion should be increased above normal levels.
The SALP Board may also include an appraisal of the performance trend
of a functional area. This performance trend will only be used when
both a definite ' trend of performance within the evaluation period is
discernable and the Board believes that continuation- of the trend may
result in a change of performance level. The trend, if used, is defined
as:
Improving: Licensee performance was determined to be improving near
the close of the assessment period.
Declining: Licensee performance was determined to be declining near
the close of the assessment period and the licensee had not taken
meaningful steps to address this pattern.
1
IV. PERFORMANCE ANALYSIS
A. Plant Operations
1. Analysis .
The quality of operations at Sequoyah improved during the SALP
assessment period based on the results of routine and special
inspections. During the first half of the assessment period,
several plant -trips and operational events occurred which
demonstrated that the operations area required further improve-
ment. Following an NRC/TVA management meeting to discuss the
root causes of the poor performance which caused the trips, the i
Sequoyah plant staff exhibited increased responsiveness to NRC l
issues, attention to detail, and commitment to quality.
'
Increased management attention to and involvement in the opera-
tion of the plant contributed to a Unit 2 record power run
following the management conference. Management initiatives
included revisions to the root cause assessment procedures,
establishment of a requirement for PORC approval of post trip
reviews prior to restart, increased attention to control of
plant activities, and a conscientious effort to reduce the
number of inoperable or out of service components.
i
Management attention to and involvement in the upgrading of
. operating procedures were focused both by results from NRC !
inspections, which occurred near the end of the basis period and ,
during the assessment period, and by licensee initiatives. l
Operating procedures were included in the licensee's ongoing
procedure enhancement program. Standardizing the procedure
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format and clarifying instruction steps as part of the
enhancement program were elements of the program initiated
during the latter part of the assessment period. This is a
long-term program and is not expected to be complete during the
next SALP rating period. System Operating Instruction (S01)
checklists were reviewed and revised by the licensee after NRC
inspections during the basis period revealed prcblems with the
system alignment processes. After the licensee completed these
revisions, system operating instructions were workable and
adequate. However, the procedure change process was difficult
and cumbersome. The use of night orders to circumvent the need
to revise operating procedures was stopped. TS' interpretations
were upgraded and now require specific approval prior to their
entry into the TS Interpretations log. The Emergency Operating
Procedures (EOPs) were determined to be adequate and the
corrective actions initiated by the licensee from a basis period
inspection were determined to be appropriate. The
Administrative Instruction for controlling Hold Orders was
revised to require more control by the Operations staff and more
responsibility by the persons performing the work resulting in
an improved hold order process. Upgrading cf the system logic ;
drawings for those systems. described by the Design Baseline and ;
Verification Program (DBVP) boundary was completed during the
assessment period and the drawings were returned to the control
room for use by the operators. Also, drawings essential for
safe plant operations were available in the control room. At
the end of the assessment period, a lcrg-term effort was in
progress to restore other system logics to the prinary drawirg
list and return them to the control room.
The licensee's approach to the resolution of technical issues
from an operational safety standpoint was technically sound. An
understanding of the safety aspects was apparent, and censerva-
tism was usually exhibited when responding to scfety-significant
events and issues. Notable exceptions to this generalization
were the poor planning and management ineffectiveness in dealing
with the system alignment and operability determination in
support of UHI valve repair, and in the resin transfer opera-
tions which occurred near the end of the assessment period.
Several operational plant events that occurred during the
restart of both Units 2 and 1-identified that a poor feedwater
control system design and operating philosophy existed. Changes
to procedures and specifi'c operator training to eliminate trips
and transients in this area were not initially effective. Rect
cause determinations did not involve sufficient first line
operations management efforts which resulted in a protracted
resolution process.
Improvements in the area of communications were instituted
following an incident involving manipulation of the wrong valve
by an auxiliary unit operator which resulted in a loss of RHR
suction. Control room professionalism was adequate and showed
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continued improvement during the assessment period. The
control room was upgraded through extensive cosmetic
improvements such as new carpeting, painting, and repair of
deficiencies such as roof leaks. However, several functional
deficiencies exist which affect operator performance and
effectiveness. Nuisance alarms, long-sta.nding hold orders and
Temporary Alterations (TACFs), and human factors problems
associated with steam generator level controls continued to
cause an unwarranted number of problems for the operators.
Management was aware of these problems and is addressing them in
the form of a System Engineering concept and a detailed control
room design review.
Problems continued in the configuration control area (system
alignment) through the startup of Unit 2 particularly in the
area of waste water systems. The program for controlling the
configuration and operations of the waste water systems was
changed to provide the same level of control for these systems
as was. applied to other plant systems that are under the
., authority of operations. This proved to be a positive step in
reducing configuration control errors associated with the waste
water systems. Additional changes made in the configuration
control program consisted of repeat back communication, and
separating the first and second verification by time and distance.
The latter change had been previously recommended during the
basis period by the licensee's Unit 2 operational readiness
review team, but had not yet been implemented by managcment. ;
Once implemented, these changes significantly reduced configu- l
ration control problems.
The licensee performed evaluations to confirm that compensatory
measures which had previously been established for disabled
safety functions were properly documented and were collectively
and individually capable of being performed with normal staffing
levels. Operator awareness and control of long standing TACFs
in relation to their effect on plant configuration was a matter
of concern to the NRC during the basis period and continued to
be an issue during the assessment period. The licensee took
action to reduce the number of TACFs to approximately 80, which
was 50% of the level at the beginning of the period, with a goal
of having no more than approximately 30 TACFs.
Operators were well informed in the use of emergency operating
procedures. Because of the long duration shutdown period
(approximately 21 years), the number of reactor operators
experienced in power operations was low and additional support
personnel were made available in preparation for Unit 2 restart.
These included additional management presence in the control
room, additional control room Senior Reactor Operators, and
temporary Operating Shift Advisors. Operator actions for most
events that occurred during the Unit 2 startup were appropriate.
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Licensed operators responded effectively to plant transients on
most occasions during Unit 1 startup including a reactor trip
of Unit'l caused by' feedwater control problems, a turbine trip
of Unit 1, a reactor trip of Unit 1 caused by a generator
ground, and a lightning strike of a switchyard transfonner
during a thunderstorm. .
Operators were observed to be disciplined professionals with
adequate communication skills. However, occasional lapses which
were exemplified by one instance of inadequate action by an
operator during routine plant activities occurred. This example
involved the placement of a centrifugal charging pump in the
pull to lock position which resulted in a failure to comply with a
technical specification action statement,
Control room activities were generally conducted in an effective
and professional manner. Formal communications were observed in
most cases. Operators were attentive, aware of plant conditions
and responsive to changes in plant conditions. Senior plant
management actively supported the above operator activities and i
was deeply involved in the day-to-day operation of the plant.
In addition senior plant management maintained a detailed
account of and tracked the status of known equipment
deficiencies, CAQRs, and plant parameters in daily plant
meetings. Active involvement by plant management and support of
ti.e ownership concept by the operations department had a -
positive' effect on plant operations and morale. This was
exhibited by the absence of significant- events or operating
problems during the extended power run of Unit 2. Facility
operations reflected improvements in planning and assignment of
priorities during the period. The forced outage rate for both
units during the period was extremely high as a result of the
extended shutdown. However, following the five Unit 2 trips
which occurred early in the Unit 2 startup process, Unit 2 had
no forced outages for a period of approximately 210 days.
Unit 1 experienced two reactor trips during its startup period,
followed by full availability for the remainder of the
assessment period.
Management support and insistence on the ownership concept has
strengthened the authority and role of the Operations group in
general and the control room shift supervisor in particular.
Operations personnel have demonstrated on many occasions their
willingness to suspend or delay surveillance, maintenance ard
other schedule impacting activities until they were satisfied
that the plant was in a safe stable condition and that other
plant activities in progress would not interact with the
scheduled activities to produce safety system actuations. The
absolute authority of the operations staff in these matters has
been fully supported by plant management.
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During the assessment period the licensee administered i
requalification examinations. The results from the examinations
indicated a large percentage success rate (approximately 69 cut
of 70). Nonlicensed operators were judged to be extensively
trained receiving both detailed classroom training and thorough {
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in plant on the job training. The percentage success rate for
new operating license candidates was determined to be
below average (7 out of 11 passed).
Operations shift training for newly installed plant modifica- ,
tions and for correction of operating deficiencies or events was i
adequate.- However, occasional lapses were exemplif.ied by the
shutdown margin / excessive cooldown events and rod control demand
counter problems.
During the assessment period Operating shift manning was l
adequate and maintained at the levels established during the
basis period. Several management positions were eliminated to
streamline the Operations organization which resulted in a more
effective organization.
Management stressed procedural compliance by operations per-
sonnel throughout the assessment period. This had a side effect
of improving procedures by forcing operators to have inadequate
procedures revised before they could be used. However,
instances of procedural non-compliance and deviation continued
during Unit 2 startup, such as the MSIV closures, configuration
control deviations, and Upper Head Injection (UHI) accumu'lator
venting events. Management was very aggressive in responding to
the above issues and by the middle of the assessment period
procedural adherence was adequate and improving.
In an event involving the discharge of highly-radioactive spent
resin that occurred during the lctter portion of the SALP
assessment period, it was determined that the intense management
attention given to power operations had not been applied to the
waste processing portion of the power plant and the attendant
operations support staff. This event highlighted, in that area
alerte, inadequate procedures, a casual attitude toward following
procedures, inadequate drawing control, and failure to aggres-
sively correct design problems that make cperations awkward or
could create personnel or radiological hazards. In addition,
plant management in this specific area appeared to be poorly
trained and very weak with respect to the operating and physical
characteristics of their assigned system. Finally, interactions
between the waste and water management group and other plant
management that were observed following this event did not
demonstrate a cooperative, quality-oriented approach to the
resolution of technical issues within the waste and water
management group. Plant management is currently taking strong
corrective action to improve the waste water processing area.
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L Logkeeping by licensed operators continued to exhibit weaknesses
particularly -in the areas of detailed entries, entry and exit
from Limiting Condition for Operation (LCOs), and descriptive
explanations and rationales for decisions made and actions
conducted by the operators and SR0s. During the last' two moriths- l
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of the assessment period, Operations management implemented
corrective actions in these areas by having' Operations super-
visors review logs for completeness, stand-alone entries and
supportable explanations for LC0 entries, exits and changes to
plant and equipment status. The NRC identified during the
latter portion of the assessment period a significant
improvement in the level of detail supporting log entries. The
corrective actions were effective.
Operational events in general were promptly and accurately
'
identified. Exceptions were the failure of the operations staff
to recognize problems with the excessive post-trip cooldowns,
and having a centrifugal charging pump in pull-to-lock while the
other pump was inoperable, both of which resulted in escalated
enforcement.
Emergency Notification System (ENS) reports occurred at a high
rate as a result of the special outage conditions and system
configurations. Notifications were generally conservatively
made 'and technically correct. ENS notification was not made
-
initi, ally for the centrifugal charging purp in pull-to-lock
event,. and for an unidentified RCS leakage above allowable
'
incident. DNE support of Operations in making Operability
determinations improved during the assessn.ent period. This
improvement was the result of management initiatives and
personnel changes.
As a result of the change in licensee management that occurred
at the'end of the basis period, PORC reviews became aggressive
and technically involved in the resolution of issues affecting
the safe operation of the unit. Changes in PORC activities
which resulted in improved performance included consistency in
personnel staffing and the high expectations established by the
new plant manager. The elevated expectations were also strongly
supported by the new site director and upper TVA management. As
a result of the TVA management initiatives, the Plant Operations
Review Staff was established as a part time support group for
PORC. P0RS employed specialized training and skills to perform
root cause evaluations and determine corrective action plans
associated with plant events, which were then submitted cs
completed projects to PORC. The use of the Plant Operations
Review Staff has involved the PORC deeply in day-to-day plant
operations.
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[ eat the close of the:SALP assessment period Sequoyah upper line
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management was found to .be strongly comnitted to obtaining ;
quality'in plant operations. .There was also a general increase- .
.in management attention toward the ccnduct of operations and- l
. management awareness of plant conditions. These, coupled with !
organizational changes to reduce both. management resistance to i
change; and the number of management levels, resulted in _ _ l
'
continuing improvement'in the performance of the operating staff l
-
and the resolution of technically diverse and complex issues !
$ throughout the year. ;
p i, During this assessment period the entire fire protection staff ;
at Sequoyah was reorganized into a Fire Operaticns Unit. The l
Fire Operations Unit consists of a dedicated fire brigade which :
'is responsible for fire suppression and fire prevention ,
inactivities. The dedicated fire brigade replaced the preexisting ]
system of_ a fire brigede composed of unit operations personnel. 1
Fire: brigade' training at TVA's Nickajack Fire Training Center j
was fourd to be excellent and brigade manning was determined to i
be adequate. Reorganization of the fire protection staff j
. greatly improved fire brigade effectiveness and fire prevention !
activities during this assessment period. Organizational i
planning and assignment of- priorities was demonstrated in the l
fire ' brigade reorganization. In general, policies and pro- ,
~Under the reorganized
'
cedures were well stated and understood. !
fire operations unit, decision making was usually at a level !
" that ensured adequate management review. Involvement by ;
corporate management in the fire protection area was evident.
Two . Fire' Protection QA Audits were performed during the SALP j
i
'
assessment period, one of which was by the licensee's insurer,
. American , Nuclear Insurers ( ANI). These audits icentified a i
number of unsatisfactory conditions and findings and reccarended i
several program improvements. The licensee either implemented i
E the - corrective actions associated with these findings or
evaluatcd the issues to develop a schedule date for completion ;
of the corrective' actions. The NRC identified weaknesses in
~
the areas of procedural implementation of fire penetration ,
barrier requirements and control of combustibles. The new fire i
protection management was aggressive in the resolution of these i
issues and appeared to take appropriate corrective actions. !
!
^
. The condition of Fire 4arriers, surveillance of fire protection l
syst' ems and components, emergency lighting, manual equipment and l
QA audits were satisfactory in terms of the low number of l
deficiencies noted. Housekeeping practices and conditions ;
relative to fire. protection wera found to be adequate. l
l
During the SALP assessment period inadequacies in the perfor-
mance of fire watches were noted. The inadequacies consisted of ;
inadequate inanagement oversight in regar d to fire watch per-
y
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sonnel and failure. of management to provide concise guidance on
how fire watch individuals must perform their duties. This
issue occurred at the time that the new organization was being
put into place and was aggressively pursued by the new fire
organization management.
Five violations and one deviation were identified: j
a. Severity Level III violation for failure to comply with TS !
3.0.3 involving loss of safety functions and for failure to
notify the NRC in a timely manner. (88-20-03 & 88-20-04)
b. Severity Level IV violation for failure to implement
configuration controls. (88-26-01)
c. Severity Level IV violation for failure to meet require-
ments of TS 3.3.1 and 3.3.2 to place OTDT and OPDT in trip.
(88-39-02)
d.- Severity Level IV violation for failure to perform fire
watch patrols. (88-46-01)
e. Severity Level IV violation for performing a test of the
TDAFW pump without a written procedure. (88-48-02)
f. Deviation for failure to comply with a commitment made
concerning the control of combustibles (wood) in safety-
related areas. (88-54-01)
.
2. Performance Rating:
Category 2
3. Recommendations:
The Board recognized that significant experience was gained
through the plant events and activities which occur ed ,
during the assessment period and resulted in an improvement
in the plant operations area.
Radiological Controls !
B.
1. Analysis
During the assessment period, inspections were performed by the
resident and Regional office staff in the areas of ram *+'on
protection, radiologi, cal effluent, and confirmatory meure-
ments. Included in the inspection program was a special team
inspection for restart of Unit 1 and a special team inspection
to assess the performance of health physics, chemistry, and
radioactive waste processing during the recent outage.
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The' qualifications of the new Superintendent of Radiological
Controls posi* ion were determined to have met the requirements
- discussed _ in Regulatory Guide 1.8, Qualification and Training of-
Personnel for Nuclear Power Plants.
The licensee's health physics, radwaste,. and chemistry staffing
levels were adequate and compared well with other utilities -
having' facilities of'similar size. An adequate number of ANSI
qualified licensee health physics (HP) technicians were
available to support . routine operations. During outage
operations, additional contract health physics technicians were
used to supplement the permanent health physics staff. The
overall quality and experience level of the health physics staff
is-viewed as a program strength. Radiation protection training
was considered good. The licensee's general employee training
(GET) in radiation protection was well' defined. The GET
training / retraining program not only included standard topics as
outlined in 10 CFR 19, but findings of licensee audits and NRC
inspections were factored into the training. Management support
of and commitment to training was evident in that sufficient-
time was allowed for training and employees were encouraged to
attend.
Management support and involvement in matters related to
radiation protection were demonstrated by: (1) purchasing an
automated laundry monitor to control the potential for " hot -
particles" in order to reduce exposure to personnel;
(2) installir.g seven sensitive portal monitors at the exit to
the . radiation controlled area (RCA) to be more effective in
detecting personnel contaminations; (3) establishing an ALARA
incentive program; and (4) providing corporate support in
resolving technical isst'es as related to the radiation protec-
-tion program.
Resolution of technica: issues was generally adequate; however,
a special team inspection observed, during the Unit 2 refueling
outage at the end of the assessment period, that the licensee
experienced problems in containment such as high iodine airborne
radioactivity, an unexpected increase of beta radiation levels in
steam generators, and heat stress to personnel while wearing
supplieu oar noods. These problems appeared to be caused by a
failure of licensee management to communicate and evaluate these
problems adequately. Early identification and technical resolu-
tion of the root causes were not performed in a timely manner,
which created the need for increased radiological attention,
resources, and demand for support from the radiological controls
program.
During the assessment period, a special NRC inspection team
revievied the licensee's controls for high radiation areas and
determined tw tnese controls were generally adequate.
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However, one violation was identified pertaining to two -
. Assistant Unit Operators (AU0s) who were unknowingly working in ;I
-a high. radiation area in the Unit 1 Auxiliary 8uilding created l
by an inadvertent introduction of-reactor coolant and resin into j
the CVCS demineralized resin transfer piping. The AU0s received !
doses of between 400 and 500 mrem and did 'not exceed .any l
administrative or NRC exposure limits. . It was determined that ;
~ the area was posted as a radiation area 'instead of 'a high l
radiation area 'and that the workers had neither an integrating l
dose . rate monitoring device nor an individual present with a
dose rate' monitoring device to provide radiological protection
job coverage. The licensee's immediate corrective action was to
post and lock the concerned high radiation area and to reconfirm
that other radiation and high radiation areas were adequatelv i
controlled. i
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~The respiratory protection program was reviewed by
the NRC during the assessment period and it was determined to t
the program was well defined and implemented in accordance with
appropriate regulations.
The 1987 collective radiation dose was 206 person-rem which was I
'
approximately 56% of the national average of 368 person-rem pe'r
pressurized water reactor (PWR). In 1988, the - station's
collective radiation dose was 382 person-rem, compared to 345 ;
person-rem per unit national average, which when combined with 1
the 1986 and ~ 1987 collective radiation dose ' averaged 284
person-rem for three years. However, since the unit has been
inoperative for an extended period the three ~ year average is
not necessarily comparable to similar intervals for other units.
At the end of 1987, the area of the plant controlled as
radioactively contaminated was approximately 15% of the total
area which potentially cruld become contaminated. At the end of
1988, the area contaminated was still approximately 15% and
slightly above other facilities similar in design, however, this
did not create a significant personnel exposure or personnel
contamination problem.
The licensee experienced 130 personnel contaminations in 1987.
The number of personnel contaminations in 1987 was among the
lowest in Region II. However, in 1988, the number of personnel
l contaminations increased to 409 and 155 of these were skin
l' contaminations. The increase in personnel contaminations was
due in part to startup activity at the plant, increasing
radiation levels and the increased detection sensitivity of the
new, more sensitive, portal monitors at the exit of the RCA.
Effluent summary data for 1985, IS86, and 1987, are contained
under Supporting Data and Summaries,Section I of this report.
These releases are consistent with the plant being shut down
from mid-1985_through 1987, and consequently no basis exists to
establish any trends during the assessment period.
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During the' assessment period, the licensee's program for
l' packaging, shipping, and storage of icw level radioactive waste
was - determined to be adequate. The licensee demonstrated good
w radioanalytical trend capability by' showing close agreement with
NRC results for both beta-emitting and gamma-emitting samples.
'
However, weaknesses were identified in the radiological waste
. water processing area as described in the operations section.of
g
this assessment.
Two violations were identified:
- a. 'Ssverity. Level IV violation for failure to adhere to or '
establish' procedures for performing breathing: zcne air
samples and for exposure control during steam generator
work. (08-31-02)
b. Severity Level IV violation for failure to evaluate
the radiation hazards present in the 690 foot eleva-
tion Pipe Chase in the Auxiliary Buildine. (89-05-04)
2.. Performance Rating:
Category 2
3. Recommendations:
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C. Maintenance / Surveillance
.1. Analysis
During the assessment period, the technical quality of main-
tenance and surveillance at Sequoyah was good as a result of the
many technical and programmatic upgrades which occurred. These l
programs experienced substantial organizational and~ perscnnel
changes resulting in a large number of licensee initiatives.
The addition of a new maintenance superintendent at the
beginning of the assessment period . resulted in licensee
initiatives in the maintenance area which included; increasing
the use of system engineers, the use of.new vibration monitoring
equipment techniques, maintenance procedure enhancement,
extensive Motor Operated Valve Actuators (M0 VATS) testing of
primary and balance-of-plant valves, establishment of a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
Outage Manager to coordinate maintenance and triodification work,
and the organization of maintenance and modification activities l
into train and system outages. Management of the Maintenance
Program was very effective as demonstrated by positive trends in
industry indicatcrs such as maintenance backlog, tagging,
overtime use, CAQR and LER generation, QA document rejection,
Post Modification Testing (PMT) rejection requiring maintenance
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rework, personnel contamination, industrial safety practices,
and delinquent safety-related preventive maintenance. Line
management increased its presence in the operating and work
spaces, became more aware of plant status and technical issues
and demonstrated a. commitment to the program and associated
improvements implemented during the assessment period.
l
The licensee developed a detailed program for completed
L maintenance record review, which is quite thorough and effective
l in identifying and correcting deficiencies. The use of
procedures in accomplishing maintenance activities was adequate
and improving. The quality of procedures and work requests, and
their associated review, steadily increased as a result of
Maintenance Section upper and middle level management
involvement in the licensee's program for removal, repair and
restoration of safety-related equipment. The licensee initiated
a system / train outage concept which was coordinated with unique
site electrical distribution and TS requirements. In addition,
the licensee instituted a standard maintenance practice which
established the niethod for managing, tracking, planning,
scheduling, post work evaluation of and documentation of main-
tenance work activities. This establishment of administrative
control over maintenance work activities reduced open-ended
" Troubleshoot and Repair" type work orders and provided clearer
direction to the personnel performing work in the field.
Operability determination was also added to the administrative
control process prior to closing out work orders.
The licensee's action with regard to NRC maintenance related
initiatives was generally good. The response varied depending
on the organizations involved and the time during the assess-
ment peciod when the NRC initiatives occurred. Licensee
response improved in all areas throughout the assessment
period. Responses from onsite maintenance and modifications
organizations were usually quick, professional and technically
accurate. During the initial portion of the SALP assessment
period, support for onsite maintenance related issues from the
TVA DNE organization took long periods of time. This caused
issue resolution and operability determination to lag.
However, by the middle of the assessment period DNE support
for maintenance and modification activities was much improved.
Licensee resolution of maintenance related technical issues
usually indicated technical understanding of the issues,
operational conservatism, and was generally well thought out.
Examples of well thought out maintenance activities were;
RCP trip bus troubleshooting and repair, and steam generator
tube leak resolution and preventive plugging. Those main-
tenance activities that were less professionally addressed
by the licensee included pressurizer safety valve trip
setpoint calibrations which occurred at the beginning of
the assessment period.
_ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ - _ - _ _ - _ _ _ _ _ - _ _ - _ _ _ .___ - _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ - - _ _ _ - - - - - - _ _ -
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The maintenance staff is generally well qualified and trained.
Special training was given to maintenance personnel following 4
issues related to the maintenance management system, EQ, conduct {
of testing, and configuration control. Trrining also included j
management training for all levels of liaintenance Department i
management and specific technical training for first and second
line managers to increase in-craft and cross-craft supervisory
expertise. The experience levels of maintenance department
first line supervisors averaged approximately 10 years of craft
related experience, which included several hundred hours of
craft and engineering training. The site maintained the INPO
training accreditation reccived during the basii period for
maintenance training.
During the assessment period, outage and work control
processes were established and implemented. Performance
immediately improved due to planning and assignment of
priorities. Procedures for control of these processes were well
defined, and appeared to be understood by the personnel involved
in their implementation. The technical background and level of
plant systems knowledge of the planners, coordinators and
managers in the work control / outage organization was excellent.
These positions were filled with operators, engineers, and
managers that were deeply involved in the day-to-day operations
of the plant and demonstrated excellent communications and
organizational skills.
'
' While maintenance tracking and planning was considered a
strength, maintenance outage stheduling was considered to be a
weakness. The licensee demonstrated it was capable of drafting
detailed correct 1<e and diagnostic niaintenance plans, and 1
implementing those plans in the field. However, outage and
maintenance schedules rarely had any realistic relation to the
actual work being performed in the plant and exhibited continual
and predictable schedule slips.
The licensee used the composite maintenance crew concept for
NOVATS testing, refrigeration, and general maintenance. An NRC
review of the implementation of the composite crew process at
the begining of the assessement period revealed that no
procedures addressed the training and qualifications require- j
ments for foremen supervising personnel in other crafts, for
'
craftsmen performing work outside of their craft, or for
craftsmen performing independent verification outside of their
craft. Although no plant events were attributable to composite
crews during the assessment period, composite maintenance crews
existed in, contradiction to the training and qualification
requirements for maintenance foremen and craftsmen. This
indicated insufficient management attention to and involvement
with the composite crew concept and represented a failure by
management to recognize that minimum regulatory requirements
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _
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were not being met. Once management attention was focused on-the
~
problem, a comprehensive procedure was developed to address the
composite maintenance crew concept. Corrective actions that
were initiated appeared to have resolved problems with the
composite crew concept.
The. control and use of calibrated equipment met regulatory
requirements and purchase receipt inspection and traceability of
installed materials was found to be acceptable. Additionally,
Lpost maintenance testing was found to be satisfactorily
accomplished.
During the assessment period the material condition of
. plant components steadily improved. A review of system failures
did not indicate any adverse management or maintenance
practices. Several conditions that did not constitute failures
but did affect plant operations were: leaking pressurizer safety
valves on both units, a leaking reactor vessel flange 0-ring on-
Unit 1, and unstable feedwater automatic controls for both
units. In the case of the Unit 1 pressurizer safeties and the
Unit 1 vessel flange ~ 0-ring, plant activities were well
controlled and personnel involved were technically astute and
receptive to NRC initiatives. However, in reference to
feedwater controls, less than cohesive disciplined management
activities were'noted.
. The plant's material condition, preservation, and housekeeping
status was adequate. Occasionally maintenance debris and other
material / housekeeping deficiencies existed in the auxiliary
L bu11 ding and other plant spaces. Additionally, work in progress
was often left open, uncovered, and unattended during work crew
breaks and turnover periods, Examples of these ccnditions were;
ice condenser cleanliness prior to Unit 2 initial heatup, loose
items and debris found by the NRC in safety-related electrical
panels and distribution boards.
'
During the assessment period the Preventive Maintenance
(PM) program at Sequoyah was in the midst of a significant
amount of change. The licensee initiated a PM Upgrade Program
which was very detailed and resulted in a significant increase
in' the number of PMs required for plant equipment. This PM
upgrade effort was in place for the majority of the assess-
ment period and the developmental stage will last another year.
Weaknesses were identified in the number of outstanding
delinquent PMs, and the existence of a significant percentage of
recently developed PMs that had never actually been performed on
plant equipment. The everall conclusion in the Pti area was that -
a very strong PM program was being developed with involved
management support. The program is being developed as a quality
activity and will improve the safety and reliability of plant
equipment when it is fully impleme 'ed. The results of this
effort, in the form of benefit to tant equipment, has r.ot yet
been realized. .
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Predictive- analysis techniques were well integrated into the
licensee's maintenance program. Vibration analysis and M0 VATS
testing .were active at the site and were found to be
instrumental- in the. identification of much of the corrective
maintenance. These two techniques were also found to be used as
an integral part of the licensee's post-maintenance surveillance
activities. In addition, the licensee implemented a- system
performance monitoring program to improve station reliability.
The program includes vibration monitoring, system and component
. parameter trending, System of the Month reviews, and performance
walkdowns. Upper plant management is very attuned to the
results from these maintenance techniques and plant operational
decisions were made using this data.
At the beginning of the assessment period, ' management
continued to experience' a lack of . full understanding of the
technical requirements necessary to fully resolve some NRC
identified procurement issues. Following NRC identified adjust-
ments to the program, Sequoyah established an acceptable program
for resolving replacement part issues. Following the NRC
findings, management demonstrated a clear understanding of the
issues involved, proposed timely resolution of the findings, and
proposed resolutions which were . technically sound.- In a
specific case (e.g., molded case circuit breakers), Sequoyah I
exceeded the. bulletin response requirements which enabled the
NRC to provide up-to-date. guidance ' to other licensees. In
addition, procurement and maintenance management coordinated
closely during the second half of the assessment period to ,
reduce, by approximately 50 percent, the outage work that could
not be performed due to outstanding material items.
Safety-related equipment storage continued to be well managed ,
throughout the assessment period. Several cases existed
where detailed storage and material information was necessary to
support plant operability determinations. In each case the
information was retrieved, clearly' supported operability and
demonstrated a service related role for the storage and
procurement organizations.
Staffing in the procurement and storage areas was adequate.
Staffing of the contract engineering group (CEG) was generally
good. While site and corporate management had the expertise for
the procurement operation, potential impacts on continued
performance were identified as a result of their possible
involvement in other TVA' site procurement activities.
I
During this assessment period, Sequoyah transitioned from a
separate dedicated EQ organization to a matrix organization
within the site DNE organization. This transition occured without
interruption or degradation of the quality of EQ corrective and
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preventive maintenance implementation. EQ maintenance decisions
were made at appropriate levels. Additionally, plant
organizations had well stated policies to guide them in
completing field work. Management authority and
responsibilities were defined and understood in the EQ area.
Sequoyah management continued their resolution of technical
issues in the maintenance area with conservative approaches
during the assessment period. This was illustrated by the
implementation of corrective maintenance activities to support
the qualification of silicone rubber electric cable installed
inside containment and the qualification of transmitter cable
nylon butt splices. The maintenance department was adequately
staffed with personnel having the appropriate expertise.
Surveillance performance and technical adequacy continued to
improve through an extensive surveillance review and inplant
validation process that continued throughout the assessment
period. Surveillance scheduling was reorganized resulting in
only one administrative 1y late TS required surveillance
occurring following the restart of Unit 1. This improvement in
surveillance management was the result of the licensee's
aggressive SI planning and scheduling program. The licensee's
scheduling performance of non-TS required surveillance and
preventive maintenance is less aggressive and appears to rely
heavily on input from upper plant management rather than first
and second line supervision.
In the vast majority of surveillcoces performed implementation
of the surveillance testing was excellent reflecting adequate
planning and assignment of priorities, and indicating an
aggressive level of management overview. However, surveillance
procedural adherence problems continued throughout the assess-
ment period, although improvement in this area was noted I
following the initial Unit 2 restart activities. Exampl'es of
procedural adherence problems were; surveillance of a Reactor
Coolant System (RCS) flow indicator resulting in a reactor trip
when the instrument was returned to service, and a power operated
relief valve (PORV) opening when an RCS resistance teniperature
device (RTD) was returned to service. Licensee resolution of
surveillance related technical issues reflected a thorough
understanding of the appropriate issues. Management was
responsive to NRC initiatives in that they established new
surveillance instructions in response to NRC information notices I
and bulletins. Personnel performing as test directors while
conducting surveillance testing activities appeared to have a
good working knowledge of the surveilltrce procedures and were
trained in the use of required instrumentation.
_ _ _ - _ - - _ - _ _
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A management initiative, designed to minimize the recurrence of
mispositioned valves, was to form a dedicated Operations
Department surveillance instruction performance team. Forming
such a team limited the number of people performing surveillance
instructions, increased the exposure of each team member to the
various instructions, and enhanced internal communications. The
team appeared to be effective in improving efficiency and
control. The SI team concept was a case of effective technical
resolution and management involvement that occurred during the
assessment period. ,
During the assessment period physics-related activities
associated with the restart of Units 1 and 2 demonstrated the
ability of the licensee to perform at a technical level above
that required to meet regulatory requirements. A number of
complications were experienced during startup testing, including
significant differences between the measured and predicted
critical boron concentrations on both units and a positive zero
power moderator coefficient on Unit 1. Licensee management
responded effectively to the complications which were
encountered. Management ensured that' adequate personnel
resources were allocated to properly perform the test program
and that an atmosphere existed which encouraged feedback from
the ~ersonnel invohed with the testing. This resulted in a
continuing improvement of the reactor physics testing program.
-
A significant investment was made in the training of 'inexperi-
enced personnel and in the cross training of design specialists,
which should benefit future reactor engineering activities
and result in further improvement of the program. Marked
improvement in the control of nuclear design calculations
and computer codes was observed during the assessment period.
Management involvement in assuring quality was demonstrated in
that the chemistry program was very actively supported by the
corporate chemistry staff. The staff was involved in developing
a corporate policy statement and directive which established
philosophy, directives and responsibilities for a chemistry
program which endorsed the guidelines recommended by the steam
generators owners group (SG0G) and Electric Power Research
Institute (EPRI). Management emphasized the need for quality
control in all aspects of the chemistry program to meet the
stringent criteria recommended by SG0G and EPRI for prevention
of corrosion.
Adequate resolution of technical issues was exhibited in the ,,
short term wet layup of Unit 2, the long term dry layup of
Unit 3 and the startup of Unit 2. Modifications to the moisture
separator reheaters replaced copper-nickel tubes with stainless
steel tubes, reducing the potential sour.ce of copper corrosion
prcducts to the steam generators. Replacement of all resins in
the polisher vessels prior to restart of Unit 2 was a
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contributing factor to the good water quality during restart.
Consequently, a lengthy chemistry hold was not necessary. .
However, the shortage of demineralized water limits the nunber
of polishers that can be used. The ' licensee has initiated
investigatory programs to improve the all volatile treatment
-(AVT) chemistry control program. The areas of wet and dry layup
of plant systems, and corrosion and erosion progrems were
determined to be acceptable.
Even though there were major changes in key staffing positions
in the plant water chemistry program, the defined program was
implemented with an adequate number of qualified, experienced
supervisors in accordance with licensee procedures.
As determined at the end of the assessment period, the ISI
program and procedures were acceptable and management
involvement in the ISI process was apparent. Based on a review
of ISI program submittals and program changes, TVA's responsive-
ness to NRC initiatives and staffing for ISI work was adequate.
During the assessment period the Inserv'ce Test (IST)
program and records were greatly improved and preclude the
problems identified during the basis period. Management
appeared to be involved in assuring quality in IST activities.
Responsiveness to NRC initiatives was evident. Based on
observation of in-process testing and review of IST activities,
staffing levels appeared to be adequate. IST personnel observed
and interviewed in the field conducted themselves in a
professional manner, and appeared to bc well traircd and
qualified for their responsibilities.
Seventeen violations were identified:
a. Severity Level IV violation for failure to have a procedure
for composite maintenance crews. (87-78-02)
b. Severity Level IV violation for failure to adequately l
implement surveillance involving RCS temperature, ;
containment spray system flow, and ice condenser
operability. (88-02-01)
c. Severity Level IV violation for failure to adequately
implement work instructions involving resistance
temperature detectors, a system hold onder, and the
safety-related air system. (88-17-01)
d. Severity Level IV violation for failure to have an adequate
fire protection surveillance instruction for containment
penetration sleeves. (88-19-01)
e. Severity Level IV violation for failure to have an adequate ,
SI for fire barriers. (88-19-03) )
f. Severity Level IV violation for failure to establish and
implement plant instructions (TS interpretations) that
complied with TS 3.7.1.2. (88-20-01)
E_-----_-----_--.-_---------_----------------__----____--__ _ - - - _ - - _ _ _ - . - - _ - - - - - - - - - - - - - - - - - - - - - - - _ . - - - - - _ - - - - - - - - - - - - - - - - --_-------. _ - _
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g. l Severity. Level IV ' violation for failure to implement ~{
surveillance requirement 4.5.1.1.1.6 involving cold leg' j
accumulator boron concentration. (88-20-02). 1
h. ' Severity Level IV violation for failure to control
maintenance activities related to a steam gen:.-ator level
~
. indicator, and flow transmitter 2-FT-68-718 (88-28-01).
i. Severity Level IV violation for structural walkdown issues.
-(88-29-02)
j. Severity Level V violation for failure to control work
practices involving' the installation of beveled washers, y
spring cans and anchor bolt alignment. (88-29-03) -l
k. . Severity Level IV violation for failure to perform an.
adequate ASME section XI test. (88-29-04)
1. Severity Level IV violation for UHI system inoperable due
.to failure to perform surveillance. (88-34-02)
m. Severity Level IV violation for EDG surveillance. not
performed when one EDG was made inoperable. (88-34-03)
n. Severity Level IV violation for two examples of failure to '
follow procedures for radiation monitor work. (88-39-01)'
o. -Severity Level IV violation for failure to have an adequate
work plan. (88-39-03)
p. Severity Level IV violation for failure to follow AI-47
requirements. (88-40-01)
'
q. - Severity Level IV violation for failere to follow incore
flux detector withdrawal procedures. (88-44-02)
,. 2. Performance Rating:
Category 2
3. Recommendations:
The Board recognized that improvements in the maintenance area
were the direct result of initiatives instituted by the new
maintenance management. The Board also recognizes that an
. aggressive FM program has been developed, but is not fully -
implemented, ind that benefit to the equipment has not yet been
realized.
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1. Analysis
, The inspections conducted curing this assessment period ir.cluded
i two routine Emergency Preparedness (EP) inspections and a full
participation EP exercise. .
The routine EP inspection performed March 7-11, 1988, disclosed
that the licensee had revised its system for reviewing and
approving changes to the Radiological Emergency Plan and
Implementing Procedures. The inspection noted that the changes
made under the new system were being properly cpproved and
distributed in a timely manner. Emergency supplies and
equipment met regulatory requirements. Although several key
personnel changes had occurred, personnel had been properly
trained prior to integration into the emergency response
organization with one exception. The exception resulted in a
violation for failure to provide annual retraining to an
alternate Technical Support Center communicator. In the EP
area, preparedness audits were found to meet regulatory require-
ments.
The routine EP inspection performed Septernber 1-4, 1988,
discicsed that the licensee hcd declared six Notification of
Unusual Events (!!OUE) since February 4,1988. All events were
promptly classified with the exception of a " seismic alarn
received" on February 8, 1988. The licensee's failure to
promptly report this event as an NOUE was identified as a
violation for failure to adequately -implement an emergency
procedure. In addition, a second example of failure to prcmptly
declare an NOUE en high RCS leak rate wcs also identified. The
licensee was maintaining an adequate notifications and commun-
ications capability in the event of an emergency. The areas of
shift staffing and augmentation, training, and dose calculation
< and assessment were found to be adequate ~.
The emergency exercise with full participation was conducte.d on
December 14, 1988, and demonstrated that the licensee could
satisfactorily respond to an emergency at the facility. The
most significant of the negative observations was a failure of
the Shift Operating Supervisor to recognize an explosion as an
entry into the emergency classification logic. However, the
licensec adequately demonstrated the ability to classify higher
levels of emergency after entering the emergency classification
logic. The overall performance was fully satisfactory and an
adequate critique was conducted by the licensee,
i
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Three violations were identified.
a. Severity Level V violation for failure to provide annual
retraining to an alternate Technical Support Center
connunicator. (88-18-01)
b. Severity Level IV violation for failure to promptly report
an NOUE when a seismic alarm was received. (88-33-01)
c. Severity Level IV violation for late reporting of a NOUT on
high RCS leak rate. (88-34-04)
2. Performance Rating
Categury 2
3. Recommendations
None
E. Security
1. Analysis
During the assessment period three routine security inspec-
'
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tions and one special inspection resulted in the issuance of
three licensee-identified-violations relative to key control,
unescorted visitors and officers being found inattentive to
duty. The reactive inspection reviewed the licensee's invest-
igation of suspected or alleged drug cbuse and found the
licensee's investigation and resolution to be adequate
In February 1988, the licensee performed both an Operational
Readiness Review (NSB/CA 88-01) and its annual Quality Assurance
Audit (SSA-88-06) which resulted in the identification of
persistent hardware and equipment inadequacies and the continued
dependence on compensatory measures. While no Conditions
Adverse to Quality were identified, the Audit concluded that
some of the equipment was obsolete and restricted the
effectiveness of the security program. NRC has ascessed the
Safeguards Event Logs, pursuant to 10 CFR 73.71, and found that
nearly 93% of the logged security incidents are attributable tc
failed alarms, cameras, computers and coded-key card readers.
The same assessment noted a minor reduction in the number of
compensatory measures, due to the correct prioritization of work
requests and a relatively short turnaround time for repair of
security equipment. It is noted that the licensee-identified
violations for officers being found inattentive to duty have a
,
'
direct relationship to the extensive use of compensatory
measures. Much of the security equipment was poorly designed
and installed, and has over the years fallen into a state of
disrepair such that replacement parts are not always readily
available. The NRC found several examples where vendor
furnished parts needed to be extensively altered before being
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used in the current security system. In the interim, the
licensee implemented appropriate compensatory measures.
At the Corporate level, the licensee continued to experience
attrition at its senior security management level. During this
' assessment period the ninth manager in the last 10 years re-
-
signed. As a result of this continued turnover, numerous
assessments, evaluations and studies have been conducted with
correspondingly few corrective action programs reaching fruition.
After appointment of the most recent and current managers the
NRC can now begin to see significant progress made on several
old projects, some of which have been successfully completed.
In July 1988, the licensee finalized the reorganization of its
Corporate Nuclear Security Services Branch so that there now
exists a centralized (and accountable) management system.
Within this Branch there is a security compliance section, a
consolidated plant access and screening unit, a separate section
responsible for equipment upgrade and another section tasked
with plans and procedures. A key element of the Branch is a
Safeguards Information Network which will computerize all site
and corporate data. Another indication of improvement is the
upgrading of security training and increased tactical exercises,
Multiple Integrated Laser Engagement System (MILES) is available
to add to the realism of these drills. The licensee's canine
corp is recogniz.ed by other federal and state agencies for its
expertise in detecting contraband.
At the site level, there exists a direct management matrix from
the Site Security Managcr to the Corporate Manager of Protective
Services within the Nuclear Power Group. The Site Director and
the Plant Manager have been instrumental in c'edicating site
L support to reduce the number of security compensatory measures.
While technically there is a matrixed relationship between the
site and its security organization there is a very strong
matrixed interface.
Changu to Physical Security, Contingency, and Cuard Training
and Qualification Plans were generally well-prepared and
coordinated, with one exceptior.. The licensee withdrew one
revision to the Physical Security Plan when it was discovered to
contain a number of errors and omissions. The licensee has been
very responsive to questions and concerns raised on licensing
submittals.
The NRC has noticed an improvement in the quality of the
security staff while the size of the staff has been reduced.
This is evidenced in such key elements as training and
procedural knowledge. There now appears to be a premeditated
implementation of the security program, as opposed to a reactive
security program.
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p ,
No violations were identified:
.
! 2. Performance Rating:
l'
Category 2
3. Recommendations:
The Board recommends that the licensee review it's security
upgrade priorities at all three facilities to ensure that the
Sequoyah security program continues to reduce its long term
reliance on compensatory measures in lieu of reliable security
equipment and systems.
F. Engineering / Technical Support
1. Analysis
NRC involvement in the engineering and technical support area
was more comprehensive than normally applied to licensee
activities. This resulted from interactions between NRC OSP
and the licensee necessary to achieve acceptable engineering
resolutions as described previously in the summary section and
the technical complexity of many of the engineering issues.
The Engineering / Technical Support functional crea eccresses the
adequacy of the technical and engineering support for all plant
activities. To determine the adequacy of the suppcrt previded,
specific attention was given to assurance of quality, includir.g
management involvement and control, the identification and
approach to resolution of technical issues, respersiveness to
NRC initiatives, enforcement history, opera tior,al and
construction events, staffing, and effectiveness cf training,
, and qualification. This area includes all licensee activities
associated with design baseline evaluation irrplcr.:entation in
terms of Sequoyah plant modifications, engineering and
technical support provided for operations, maintenance,
surveillance, training, procurement, and configuration,
management. This evaluation was based on Sequoyah site
inspections conducted by the NRC staff in the above areas and on
licensee technical submittals reviewed by the staff containir.g
engineering evaluations . supporting the Sequoyah Nuclear
Performance Plan (SNPP). .
Inadequacies during the basis period were in the areas of design
analysis, modification control, engineering docume nta tion ,
design basis utilization, and design verification. In order to
correct these weaknesses, TVA senior management increased their
involvement and control during this assessment period to improve
the quality of engineering support. TVA nanagement involvement
was demonstrated through issues including; the Replacement Items
Prngram, in which TVA Corporate and Sequoyah management were
greatly involved in the program to ensure immediate and effective
corrective action; the issuance and use of procedures in the
civil / structural area, including pipe supports and restraints;
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'the drawing: control' process,.which is considered .now to be .of ~
Io ' high quality and. accuracy; and the procedures .for control: of
I thermal expansion tests. The procedures used for the thermal
expansion tests were well defined and explicit, demonstrating
evidence of prior planning with a proper assignment of
priorities.
,
In . response to ' concerns expressed by the NRC, TVA revised
Sequoyah's snubber surveillance program procedures, resulting in
a- more conservative selection.of the number of snubbers to be
tested upon occurrence of test failures.
-TVA DNE continued the control of the EQ activities as had been
established in 1986 and 1987. During thisLassessment period,
Sequoyah'transitioned from a separate dedicated EQ' organization
to a matrix organization within the site DNE organization. This
transition appeared to occur without interruption or degradation
of the quality of DriE support to the plant. Engineering
decisions were made at appropriate levels. This is'a clear
assuring quality.
Other issues in which DNE management oversight and involvement
was 'strongly prevalent included DNE representation during the
morning and outage planning meetings, the initiation cf a duty
. DNE manager for weekend and back shift engineering support for
'
Op.erations, and the direct management involvement in the
organization.and allocation of resources for the P,estart Test -
Program.
TVA DNE management, hoviever, has not been adequately involved to
ensure quality in all cases. S 1
provided in Generic Letter (GL) specifically,
86-10, for spuriousthe staff guidance
actuations
from high-impedance faults had not been followed by TVA.
Similar problems with 'the implementation and ' applicability of
other portions of GL 86-10 had been previously discussed with
the licensee early in the assessment period. This instance
indicated a reliance of the licensee on the NRC to establish an ;
adequate scope and content for this generic letter with respect j
to the extent of applicability and indicated a lack of ,
!
responsiveness to this NRC initiative.
'
TVA did not follow their design commitments made to the NRC
involving criteria for pipe supports and piping analyses. These i
cases indicated a lack of management involvement in the
activities they supervise and a lack of quality verification for I
commitments made to the NRC. ,
TVA experienced problems in engineering documentation adequacy
and in the backlog of open plant change packages. For example,
TVA did not properly document changes to the Emergency Diesel
)
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Generator (EDG) 2B-B load analysis (SQN-E3-002) from Rev'ision 7,
which was used as the' basis for Unit 2 restart, to Revision 10,
in which all EDGs were analyzed. for Unit 1~ restart. Revision
10 which documented that EDG 28-B had reduced diesel generator
loading,~ 1acked complete information and required additional
supporting data to explain the leading changes. 'Furthermore,
the summary letter of EDG load analysis dated August 11, 1988.
contained three incorrect-numbers, only'_one of which was later
identified by TVA. NRC staff discussions with modification
- personnel revealed there were approximately 1300 engineering
design change workplans: remaining open, some dating back to
1980. All required physical work was completed on these work-
plans prior to plant startup, however, the workplans were
'left open!for various reasor.s. These problems indicate lack of
quality, verification for submittals made to the NRC and a lack-of
management'_invoiva ent.
The approaches taken by the site end corporate engineering-
staffs to resolve technical issues from a safety standpoint were
adequate with improvement shcwn during the assessment period.
For example, in the civil / structural area, the staff reviewed
- TVA's submittals for justifying the adequacy _of Interim (or.-
Restart) Criteria and design calculations for a. field erected
~
tank, cable tray supports, pipe supports, conduit and supports,
ERCU pipe access cells, the ERCW pump station, masonry walls,
.the steel . containment vessel, equipment supports and miscel- .
laneous civil / structural issues, and found that the engineering
records and design calculations were generally complete end
documented. However, as a result of NRC reviews, some of the
design calculations were regenerated two cr three times by TVA
before lVA was able to r'eet and implement restart requirement
design criteria which was acceptable to the NRC. The evaluation
results for' the issues' iden:1fied were' reascnable, logical and
-
net the Sequoyah restart requirements. In the area of pipe
supports, cable tray supports, pipe restraints and equipment
supports, staff review ano evaluation found that there was a
defined set of procedures for the control of engineering
activities. It was concluded that engineering records were
available, relatively easy to access and were clear. Minor
errors were found in some of the specific calculation packages
reviewed, however, the general assessment was that TVA had
improved the quality of the results of the engineering and
technical support groups.
TVA engineering personnel were found to have an understanding of !
the issues involved when evaluating changes to the facility.
The staff audited the licensee's report required under 10 CFR
'
50.59 supporting the seismic qualification of the interim and
final designs associated with the component cooling water (CCW)
heat exchanger replacement and associated piping modifications.
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The detailed analyses provided to the staff exhibited a
comprehensive evaluation of the CCW system to justify continued
operation of Unit I while the piping modifications were being
implemented. The engineering records were extensively
documented and readily available for staff audit. The licensee
exhibited a thorough understanding of the technical analyses and
clearly explained the rationale for allowing continued operation
of Unit 1 during the CCW heat exchanger changeout.
Further examples of adequate TVA engineering reviews included
the piping thermal expansion test program which demonstrated a
sound and thorough approach to identifying potential inter-
ference to piping thermal growth as a result of implementation
of plant modifications. Also, TVA's response to the staff's
concerns regarding potential damage to the containment during
the Sequoyah extended shutdown period demonstrated a sound
approach to resolving the staff's concerns.
However, in several instances during the assessment period, TVA
actions indicated an inconsistency in the thoroughness of
technical resolutions and a lack of attention to detail.
Examples of weak technical resolutions and lack of thoroughness
included TVA's initial cable testing program, EDG voltage
analysis (SQN-E3-011, Revision 2,) and a proposed TS change
which applied to the Turbine Driven Auxiliary Feedwater Pump.
(TDAFWP). TVA demonstrated a general understanding of the
safety issues' involved, however, the engineering analysis
accompanying these issues did not reflect an indepth review of
all applicable safety aspects. The DNE effort supporting the
Sequoyah Unit 2 pressurizer safety valve steam trim / leakage
resolution was another exmple of a lack of effective DNE action
to resolve plant problems.
The staff audited the licensee's modification to correct a
deficiency in the teismic qualification of Bailey Meter elec-
trical_ instrumentation cabinets involving the use of aircraft
cable. The staff found the licensee's modification to be ;
unacceptable. The licensee did not demonstrate an under- i
standing of the seismic qualification requirements for the l
Bailey Meter cabinets and thus its fix, using aircraft cable, j
was not sound. In addition, only after the modification using i
the aircraft cable was found to be unacceptable, did the f
licensee establish that the electrical instrumentation was not
required for safe shutdown.
'
While the level of cooperation between DNE and plant personnel
has substantially improved, the technical adequacy of the
engineering support has not been of a consistently high level.
While progress over the assessment period was evident, errors
and incomplete evaluations have continued.
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' During the assessment period, tha licensee generally responded
well to NRC initiatives. While NRC'had to. insist on cable type
-
'
testing, TVA has since been responsive in all remaining areas of H '
the cable testing program. . Other examples of TVA's responsive-
ness .were demonstrated in the ' area of procurement. In.a few - ;
Leases (e.g. molded case circuit. breakers) Sequoyah engineering- l
staff exceeded reporting requirements to the NRC with respect to l
reporting the s_ cope of problems. ThisJ assisted the NHC in !
providing up-to-date. guidance to other licensees..'In the area !
> 'of fire protection,- responses to NRC requests have generally -
been timely as well;as thorough except for certain provisions of
GL 86-10. An exception was_in the area'of~ establishing welding >
inspector certification where records were not complete nor well
maintained and corrective action was not timely. Other respon- i
'
sive efforts worth noting include the timely corrective action
taken for problems identified during the pre-operational thermal j
expansion- test program. These efforts represented timely ;
corrective action implementation for an NRC initiative which ;
went beyond minimum NRC requirements and, with TVA's proper i
completion - of = the test program, significantly enhanced the
reliability of the Sequoyah piping systems.
During the assessment period two violations were issued in the !
Engineering / Technical Support area. The first violation was for '
failure to take adequate corrective action and follow procedures ;
relative to dedication of commercial grade items for use in ;
safety-related applications. While NRC had observed improve- l
ments in TVA's procurement of purchased parts due to previous i
corrective actions, the inspection determined that Sequoyah was
still procuring commercial grade parts without adequate H
dedication of the parts for use in safety-related applications. j
The second violation documented that TVA did not have hydraulic -j
+ . and thermal design calculations for the containment spray l
system, which estcalished the design basis for the pressure ard
temperature bourcaries. Corrective actions for both of the
above violations have been implemented and were determined
edequate.
Operational and construction events which involved TVA )
engineering have been properly reported to the staff via the
Licensee Event Reporting system. Engineering support for these ,
occasions was adequate to support both proposed and implemented j
'
corrective actions. !
l
TVA staffing levels in the engineering / technical support area,
including management, were adequate. Position identifications I
and definitions of authority and responsibility were well
established and managed during the assessment period. In the
civil / structural engineering area, the items that required
resolution by TVA engineering from the NRC's Safety System l
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Quality Evaluation, were in some instances delayed because of '
lack of available staff. However, this was noted as an
exception rather than the norm.'
9
The effectiveness of TVA's training and qualification programs
in engineering and technical support has generally been adequate
with a few exceptions. Lack of adequate training was a major
cause of a violation in the procurement area. A lack of
adequate training in administrative procedures was found to j
be a major contributing factor in ISI training and documentation j
problems and in the reluctance by the ISI group members who
performed radiography on welds to follow administrative
requirements for procedure changes. These events were
inconsistent with the observed results of training for other TVA
organizations (e.g. plant modification training, maintenance
craft training, and Shif t Technical Advisor and Operator
training). The pre-operational thermal expansion test program
engineers were noted as being well trained ano qualified for the i
performance of their required duties. In general, the training
and qualification programs contributed to an adequate under-
standing of work and general adherence to procedures. The number
of exceptions were acceptable. Management of the training and
qualification program within the ISI area was inadequate in that
adherence to administrative procedures was not enforced.
Two violations were identified:
a. Severity Lesel IV violation for failure to take adequate
corrective acticn and follow procedures relative to
dedication of commercial grade items for use in safety-
related applications. (88-07-01)
b. Severity Level IV violation for failure to hase hydraulic
and thermal design calculations for the cont 6inment spray
system. (88-29-01)
2. Performance Rating:
Category: 3 Improving
3. Recommendations:
The Board is encouraged by the initiative and efforts expendeo
by TVA to improve the quality and effectiveness of its ,
engineering suppcrt for the Sequoyah Nuclear Plant. The Board
recognizes that a significant amount of complex engineering work '
was completed. Since considerable NRC effort and input was
needed to obtain acceptable engineering resolutions, the 00ard
concluded that TVA has not yet demonstrated independent
performance at a level greater than that necessary to meet
minimum regulatory requirements. The Ecard recoiserds that
!
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i
management attention to this area continue, that those long term j
commitments made ' to assure continued improvement after the '
initial restart of both units be completed as scheduled, and
that adequate long term staffing and funding be maintained to i,
'
support completion of the long term commitments.
G. S_afety Assessment / Quality Verification
1. Analysis
The area of Safety Assessment / Quality Verification included
quality assurance and the corrective action process, safety
committees, the 10 CFR 50.59 safety evaluation program, event
reporting and root cause assessment, the employee concerns
program, licensing activities, and corporate support for quality
verification. The most significant improvement *las i~n the
corrective action program which is now functioning adequately.
Improvements were ncted in safety committee performance and root
cause assessment. Weaknesses were noted in the 10 CFR 50.59
safety evaluation program.
While both site and corporate management were involved in the CA
area and the policies were adequately stated, NRC inspections
and other NRC staff reviews and evaluations indicated that all
new policies were not fully understood by Seoucyah personnel.
Problems continued to exist during the early part of the rating
period in the corrective action process and cdequate corrective
action was occasionally not effective resulting in repetitive
CAQRs. In addition, CAQR resolutions were sometimes delayed.
Changes to the QA topical report are requirea to be submitted to
the NRC at least yearly. TVA made several extension requests
for submittal of changes indicating a slow approval process end
a reliance on the NRC to establish an adequate time frame for
submittal. * While the violations that occurred during the
assessment period have not been directly related to the QA
program, they have involved failure to follow procedures or
failure to take adequate corrective action.
Key positions in the QA department were identified and
authorities and responsibilities were well defined. The staff
expertise level was considered excellent. Trcining contributed
to an adequate understanding of the QA prcgram.
The licensee continued the implementation of the CAQR program
which was established during the basis pericd. Early in the '
assessment period CAQR reviews indicated weaknesses in opera-
bility and significance determinations, reviewer and management
training, timeliness, documentation, and auditability of re-
cores. The Sequoyah Site Deputy Director personally took charge
of the implementation of the Sequoyah CAQR program to ensure
that implementation problems would be resolved. The CAOR
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process required an encrmous amount of dedicated upper nanage-
ment effort to ensure that it contir:ued to function adequately.
.One major reason that the dedicated management attention was i
,
necessary was that a large number of issues were identified at
! Sequoyah, and at other TVA plants which had implications on
Sequoyah, that required resolution through the corrective action
program, resulting in a significant CAQR backlog. A second
reason was that time-sensitive equipment operabilty determina-
tions en engineering issues required determinations prior to the
completion of the CAQR technical evaluations resulting in the
required use of large amounts of predecisional information. The i
corrective action process was determined to be adequate to allow
the restart of both units. To this end an order, which dealt
with a management breakdown in controls fcr safety concerns
having generic implications to other TVA sites, was considered
adequately resolved for Sequoyah.
In order to reduce the amount of dedicated upper nanagement
effort necessary to make the CAQR system work, the licensee
developed a change to the CAQR process and implemented it in
September 1988, immediately prior to the restart of Unit 1. The
change provided several administrative control programs to act
ds Corrective action screening processes. Those issues that did
not meet the acceptance criteria for being a CAQR stayed in the
administrative control programs for resolution. A Quality
Verification Inspection (QVI) conducted near the end o' the
-
assessment period fcund that the changes were adequately
implemented and strongly supported by ser.ior line n;anagement.
The char.ges appeared to have the desired effcct of forcing
insignificant and less significant issues down to the proper
level for resolution, while keeping safety significant items at
the senior management level.
The QVI reviewed for quality and quality verification in the
areas of plant operations, surveillance, maintenance, corrective
actions,* modifications, and implementation of commitments made
to the NRC. The QVI concluded that site line management was
strongly dedicated to quality and was convincing workers that
quality work was what was expected. One exception to this
attitude was in the radwaste processing area as revealed by a
resin transfer event that occurred at the end of the assessment
period. This event indicated that management attention had been
lacking in the radwaste processing area and that overall site
procedure upgrades had not had an effect on upgrading quality in
this area.
The function c' the quality monitoring organization was to
assist site management in meeting quality objectives by
identifying ccr.ditions adverse to quality on a real-time basis
before they impacted on nuclear safety, reliability, or
_ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ -
_
_ _ _ _ _ -__
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50
,
component' operability. The quality monitoring organization was
observed to be a well qualified and adequately staffed
organization which was adequately performing its function.
The use of interfaces between groups, by the organization as a
whole, to verify and accept quality when deliverables were
trar,sferred was not emphasized as a quality verification tool.
For example, the maintenance department was using an interface
organization between the shops and QA to ensure that completed
surveillance tests represented quality work prior to their
transfer to QA for review, however some of the problems that
were being identified for correction had resulted because
procedure changes had not been adequately communicated to the
shop organization responsible for perfchaine them. An interface
problem was also identified between engineering and the plant in
relation to vendor manuals having conflicting data and resulted
from a lack of communication between the two organizations. ;
Although interface problems between engineering and the plant
were identified by the NRC staff during the basis period, inter-
faces were-not actively used by site or corporate mar,agement for
the purpose of quality verification.
The licensee identified that the percentage of Boron-10 isotope
in the boron being added to the reactor coolant was outside of
the established procurer:ent and design specifications. Although
this and related nonconforming ccnditions were identified by
licensee personnel on at least three distinct occasiens, the
established corrective action process ecs not implemented in a
timely manner and was only initiated after the issue was raised
by the NRC. Once identified by the licensee, corrective actient
were adequate.
The licensee's 10 CFR 50.59 program was reviewed and in most
cases found to comply with minimum regulatory requirements,
however weaknesses were identified. The first weakness was
identified as a violation and related to non-conservative
translation of regulatory requirements into procedures; the
second weakness was related to the lack of qualification
requirements for the performance of screening reviews; the third
weakness was related to a lack of definition for when
interdisciplinary reviews were required, and the fourth weakness
was related to coordination of the reviews between groups.
These weaknesses indicated minimal management involvement in
assuring the quality of this function. In addition, a failure
of the 10 CFR 50.59 process was identified in relation to the
,
excessive post trip cooldown effect on shutdown margin which was
identified early in the assessment period and issued after the
end of the assessment period as a Severity 1.evel III violation.
1
'
A reorganization of the Plant Operations Review Staff (PORS),
i
which is responsible for reporting and investigating plant
'
events, occurred at the beginning of the assessment period. NRC
- _ _ _ _ _ - - _ _ _ _ _ - _- _
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.. 51
concerns about inadeouate root cause analysis for- plant events
were addressed by prcviding training for the PCRS staff. Root
cause determinations and licensee corrective actions improved
throughout the SALP period and have becore more reliable and
technically correct near the end of the period. One failure of
'
the root cause reviews was in the area of excessive post trip
cooldowns and the resulting effect on end-of-life shutdown
- margin which was issued after the end of the assessment period
as a Severity Level 111 violation.
The objective for ISEG and the other safety review committees to
identify underlyinc problems before they become issues was
recognized by TVA management. The safety comnrittee reorganiza-
tions which occurred near the end of the basis perioc began to
have an effect in accomplishing that objective during the
assessment period. PORC was more aggressive and technically
involved in the resolution of issues affecting the safe
operation of the units. PORC improvements were due to
consistency in perscnnel staffing, strong leadership from the
new plant manager, and use of the Plant Operations Review Staff
(PORS) as a part-time support group for PORC. FORS employed
specialized training end skills to perform root cause
evaluations and determine corrective action plans associated
with plant events, which were then submitted a:. completed
projects te PORC. The use of the P0RS to perform investigative
data gathering and initial evaluat. ions has allowed PORC to be
'
more deeply involved in day-to-day plant eversight. The NSRB
has continued to chcw a low profile with respect to crisite
ectivities functioning principally in the areas of LER
evaluation, TS change approval and cther area:: that allow fcr
offsite review. The ISEG was reorganized as a result of a
TS change and became more aware of industry issues, showed a
greater presence in the plant, and by the end of the assessment
period, was becoming an effective auditor of piant activities.
Near the end of the period, ISEG and the other safety committees
were working together better in understanding what each of their
roles should be in accomplishing the overall objective. j
l
A broad spectrum of safety issues was identified by TVA
employees in the ECTG program which reflected a previous lack of
management involvement with quality. The NRC staff review of
the Sequoyah ECTG investigations, corrective actions, and
planned programmatic improvements concluded that the evaluations
were generally adequate and well documented. I
i
I
The Employee Concerns Program (ECP) continued to be implemented
in an impressive and professional rcnner. Several audits cf ECP
open files ar.c' concerns were completed with no significant 1
l
findings or wealnesses. Restart determinations performed on
open files and concerns were accurate and conservative.
Followup on issues which were both NRC issues and ECP issues
]
_ _ _ _ _ . _
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,
resulted in parallel, conservative conclusions. The ECP
encouraged the return of issues to line managenent for
resolution ar.d in dolng so, has strengthened line inanagement
responsiveness to issues identified by non-canagement employees.
There was a tremendous amount of activity in the licensing area.
Supplemental information regarding licensing ectivity is
provided in Section F, under Supporting Data and Summmaries.
Generally, the large majority of the work done by TVA on
licensing issues was good and showed evidence cf prior plenning
by management. Hcwever, TVA had a tendency to be optimistic in
i
establishing submittal dates which has resulted in frequent
requests for extensions. Ir. addition, two examples, TSCR 87-47,
'
Control Poom Emerger.cy Ventilation System, and ISCR CC-21, River
Water Level and Temperature, were noted where TVA knew that a TS
l
change would be needed and the submittals were not made on a
timely basis,
i
Submittals by TVA generally shcwed an understanding of the
technical issues beinD discussed. The approach to the technical
'
l
issues exhibited conservatism and were viable, thorough, and
j generally sound as demonstrated in their quick response to a
l
primary to secondary leak that developed in a Unit 2 steam
generator during start-up, in their response to hCC Eulletin
88-02, " Rapidly Propagating Tatigue Cracks in Steam Gercrator
Tubes", and in their sube dttals requesting relie' from ASNE code
Section XI, inservice Inspection and Operating Plant Cece. In
additicn, TWs proposal tc revise ira;trument accuracy
calculations for the PCP undervoitage reactor protection channel
in TSCR 87-18, RCP uncervoltege reactcr trip, could Le censidertd
illustrative of a rigorous evaluation cf technical problems and
a timely update consistent with ir.dustry practice. This,
however, was t.ot true for TSCR 88-T0, Upper lieed Injectinn
Accumulator Level Switch Setpoint which was submitted without
TVA understanding thet its application dia net meet 10 Cfh
50.46(a)(1) and therefore required an exarption.
Conservatism in the licensee's alternate approach tc problems
was generally exhibited and decisicn making was usually at a
level that ensured adequete managerent review. The technical
reviews occasicnbily were lecting in detail and/cr technical
basis. Licensee statements at meetings were not always well
thought cut prior to presentation to the NRC indicating that
communication between licensee organizations was not always
clear.
TVA was generally responsive to NRC initiatives. NRC
expectations regarding the issue of Ste6m Binding of Acxiliary
Feedwater (AFW) pumps were met in the area of technical accuracy
and were exceeded in the area of scheduling. The overall
_ -
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, ._ __ __ _ _ _ ___
,
,: '
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,'
t
Y s. S3
staffing to support operating activities was adequate with the
>y. licensing engineer-being well qualified and adequately trained.
- The site licensing organization has been successful in improving- 1
h . the timeliness and quality of responses to NRC violations.
'
TVA Nuclear Power cor) orate management was usually involved in
Sequoyah site activit'es in an effective manner. The corporate
level was reorganized on-~ July 1,1988, as part of a general
reorganization of TVA itself, and resulted in a reduction in the
number of levels of management between the Senior Vice President-
Nuclear Power, who is manager of the TVA nuclear power program,
and the site. Also, the manager of the TVA nuclear power
program, who was a contract employee, was replaced by a perma-
nent TVA employee. The emphasis of TVA's nuclear power program
has switched.to operating the Sequoyah units within constrained
TVA budgets, compared to past budgets, and reduction-in-force
within TVA's nuclear power program including the site. The
effects of the new emphasis is ur.certain, however, the NRC has
noted that TVA was reassessing the' dates and scope for commit-
ments.
Corporate support for site activities was observed in the areas
of Operations, Quality Assurance, and outage inanagement. The
support in these areas was limited to activities and managers
necessary . to support the restart of Units 1 and 2 and the
refueling of Unit 2. The support was not global in nature and
. consisted mainly of loaned corporate managers and specialists
that met specified needs. Activities appeared to be well
supported by corpor~ ate management and the mai. agers supplied by
corporate management were professional and well suited to the
assigned tasks. A site Radiological Assessor position has been
established. The position reports to the Manager of
Radiological Control, a corporate position rather than to the
Site Director. The position provides a programmatic cverview of
the- Sequoyah radiological control program and an independent
reporting path offsite. The Site / Corporate interface was
adequate and programmatic overview of the site was occurring.
For the assessment period, ccrporate mt.negement continued to be
generally responsive to NRC initiatives. The responses to NRC
were generally timely, sound and thorough. /ilthough Unit I was
restarted in November 1988, the restart date was only three
months later than originally scheduled by TVA, as compared to
(. two years later for Unit 2, which showed evidence of improved
L planning and assignment of priorities.
.The significant exceptions to TVA's general responsiveness to
NRC initiatives and timely submittals in the rating period were
the resolution of the silicone rubber insulated cable testing
issue and the tardiness of TVA in submitting Revision E of the
Corporate Nuclear Performance Plan to reflect the July 1,1988
reorganization.
.
I _ _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ . . . . , _ . . _,
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Seven violations were identified:
a. Severity Level IV violation for failure to follow
procedures for authorization to exceed plant overtime
limits.(327,328/87-70-01)
b. Severity Level IV violation for failure to follow
procedures for installation and inspection of seal table
bolts. (327, 328/88-09-01)
c. Severity Level IV violation for failure to take prompt
corrective action for deficiencies in QA record storage.
(327,328/88-09-02)
d. Severity Leve'l IV violation for failure to properly l
translate 10 CFR 50.59 requirements into instructions or
procedures. (327,328/88-43-01)
e.. Severity Level IV violation for failure to take adequate
corrective action for prevention of reactivity changes
while both trains of control room ventilation are
inoperable. (88-27-01)
!
Severity Level IV violation for failure to. take adequate
'
f.
corrective action to preclude repetition of violation
87-S0-01 involving lack of control over plant evolutions, ,
and system and equipment status in the radioactive weste -
area. (88-50-01)
g. Severity Level IV violation for three examples of failure
to promptly identify and initiate adequate corrective
action for Boron-10 procurement problems. (88-60-01) l
2. Performance Rating
' Category: 2
3. Recommendations
None j
V. SUPPORTING DATA AND SUMMARIES
l
A. Investigation Review
The NRC's Office of Investigations closed fourteen cases which dealt
with TVA during the assessrrent period. None of these involved
enforcement action pertaining to Sequcyah.
l
1
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. 55
! B.. Escalated Enforcement Action
1. Civil Penalties
4
Severity Level III violation issued on July 3,1988, concerning
failure to ccmply with TS when both centrifugal charging pumps
were inoperable and failure to report this condition pursuant to
10 CFR 50.72. ($50,000 CP)
,.
2. Discretionary Enforcement for Shutdown Plants
Failure to meet the 10 CFP 50.59 requirements for a 1984
auxiliary feedwater pump modification. No Notice of Violation
or Civil Penalty was issued as discussed in a letter dated
May 9, 1988.
C. Licensee Conferences Held During Appraisal Period
During the appraisal period, meetings were held with the licensee to
discuss various issues, as follows:
1. Management Meetings
Date Purpose
February 11, 1988 Meeting to discuss load sequencing of
plant diesel generators.
March 09, 1988 Meeting to discuss technical issues related
April 14, 1988 Meeting to discuss differences between
Sequoyah, Units 1 and 2 in the Sequoyah
Nuclear Performance Plcn.
April 29, 1988 Meeting to discuss (1) the Unit 2 steam
generator tube leakage and (2) loop seals '
.
for the pressurizer safety valves.
June 13, 1988 l'eeting to discuss the restart of Unit 2 in
light of the five scrams from power in
May 1988.
June 22, 1988 Meeting to discuss the TVA commitments for
Unit ?.
July 21, 1988 Meeting to discuss Phase II of the Design
Baseline and Verification Program fcr
Sequoyah.
September 8, 1988 Meeting to discuss changes to the TVA
Conditions Adverse to Quality Program at
-
Sequoyah.
_ _ _ - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ .
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4
56
September 13, 1988 Meeting to discuss TVA's preparation for
Unit I restart and the post-trip cooldown
shutdown margin issue.
September 15, 1988 Meeting on TVA's Microbiological 1y
Induced Corrosion Program at Sequoyah.
October 24, 1988 Meeting on the status of TVA's commitments
to NRC on Sequoyah.
November 28, 1988 Meeting on the Essential Raw Cooling Water
'.
pumphouse formulation and roadway access
cells.
2. Enforcement Conferences
March 17, 1988 Enforcement Conference at Sequoyah
concerning centrifugal charging pump
operability which resulted in EA 88-86.
(IR 88-20)
July 28, 1988 Enforcement Conference at Sequoyah
concerning upper head injection system
operability. Issued as Severity Level IV.
(IR88-34)
December 19, 1988 Enforcement Conference at NRC Headquarters
concerning the affect of excessive cooldewns
following reactor trips on end-of-life
shutdown margin which resulted in EA 88-307.
(IR 88-35 & 88-55)
D. Confirmation of Action Letters
1. April 26, 1988 Reinstatement of Hold Points for
Unit 2 Restart from Steam Generator
Outage
2. June 16, 1988 Confirmation of Release from Unit 2
Hold Points
3. November 7, 1988 Reinstatement of Unit 1 Mode 2 Hold
Point
a
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
_ _ _ _ _
'
.
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, . 57
E. Review of Licensee Event Reports
During the assessment period, there were a total of 78 LERs analyzed
for Units 1 & 2. The distribution of these reports by causes, as
determined by the hRC staff was as follows:
LER CAUSES UNIT 1 UNIT 2
Component failure ................. 2 6
Design ............................ 2 1
Construction / Installation /.......... 1 3
Fabrication
Inadequate Procedure............... 11 3
Test Calibration.................... 7 3
0ther............................... 7 3
Personnel
- operati ng acti vity. . . . . . . . . . . . . . . . 5 6
- maintenance activity.............. 2 4
- test / calibration.................. 2 6
- other............................. 3 1
Total 42 36
F. Licensing Activities
The assessment of licensing activities was based, in part, upon
licensing actions successfully completed duri,ng this period. These
- include the following:
1. Discretionary Enforcement /ilaiver of Compliance
January 30, 1989 Emergency Diesel Generator Surveillance
Testing
2. Reliefs Granted
February 8,1988 American Society of flechanical
Engineers (ASME) Code Case N-411
May 11, 1988 ASME Code Section XI Relief for the
Microbiologically Induced Corrosion
(MIC) Program
August 18, 1988 Hydrogen Analyzer Sampling Valves,
ASf1E Code.Section XI Relief
September 15, 1988 ERCW Valves on CSS Heat Exchangers,
ASME Code Section XI Relief
September 15, 1988 Generic Relief on Use of Ultrasonic
Monitoring of Pump Flow
November 4, 1988 Temporary Deviation from Appendix R to
to 10 CFR 50, Section III.G.
. .
_ _ _ - _ _ _ _
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.
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- 58
3. Exemptions
July 14,_1988 Schedular Exemption to Appendix J,
Type B and C Testing
September 22, 1988 Exemption to Appendix J. Type C
-Testing for C/RHR Spray System Check
Valves
October 26, 1988 Temporary Exemption to Appendix K ECCS
Calculations to May 31, 1989
January 26, 1989 Exemption to 10 CFR 50.46(a)(1),
Approved ECCS Analysis for Operating-
Cycle 4
4. Orders
March 31, 1988 Modification of Order 85-49 stating
that Sequoyah had satisfied the
requirements of the Order.
5. Emergency or Exioent Technical Specification (TS) Amendments,
June 30, 1988 Exigent TS /cendment on Ct rporate -
-
Reorganization
January 3'0, 1989 Emergency TS Amendment on Diesel
Generator Surveillance Testing
6. Malti-Plant Actions (MPA) Resolved
Date MPA Description
fiarch:21, 1988 F-05, Procedures Generation Package
May 5, 1988 A-21, Pressurized Thermal Shock
May 18, 1988 B-60, Environmental Qualification
for Unit 2
July 20, 1988 B-98,Bulletin 85-01, Steam Binding of
AFW Pumps
September 9, 1988 B-101, Boric Acid Corrosion of Carbon
- Steel RCS Components
November 28, 1988 B-81, GL 83-28, Items 4.2.1/4.2.2
February 3, 1989 B-60, Environmental Qualification for
Unit 1 _
.
' - _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _
. _ _ _ _ _ _ - . ._ ______
'
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,
l
59
7. Significant Plant-Specific Issues Resolved
Date Description
February 23, 1988 Sequoyah Pipe Support Criteria
February 23, 1988 Unit 2 Extended Heatup Prior to Restart
March 11, 1988 Unit 2 Restart Employee Concern Element
Reports
March 14, 1988 Revised Sequoyah IST Program
March 21, 1988 Hydrogen Analyzer Operability
May 18, 1988 NUREG-1232, Volume 2, Review of
Sequoyah Nuclear Performance Plan for
Unit 2 Restart
May 25, 1988 Silicone Rubber Insulated Cable Inside
Containment
June 23, 1988 Bulletin 86-02, Static-0-Ring Switches
Jul.y 6, 1988 GL 87-06, Periodic Verification of PIV
Leak Tight Integrity
August 3, 1988 10 CFR 2.206 Petition on Emergercy
Diesel Generators
September 22, 1988 JC0 for Operation with C/RHR Spray
_
System Check Valves without
Appendix J, Type C Testing
November 4, 1988 Unit 1 Restart and Both Units
Non-Restart Employee Concern Element
Reports
December 5, 1988 GL 87-12, Loss of RHR with RCS
Partially Filled
February 3,1989 NUREG-1232, Volume 2, Supplement i
Review of Sequovah Nuclear
Performance P' for Unit 1 Restart
.
.
d
. _ _ _ _ _ _ _ _ _ _ _ _ _ __ __ __ _ _ __ _ _ _ _
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E 3 7 4
B 1 1 70
M - - -
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U 8 9 8 -
N 8 8 8
S S S S
T T T T
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E 9 9 9
U 8 8 8
S / / /
S 0 0 1
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3 3 3
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E 1 1 1
T 0 0 0
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NT 7 8 8
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8 8
TN
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, 63 i
G. Enforcement Activity ,
l
All violations for the appraisal period were cited against Unit 1 I
and Unit 2.
NO. OF DEVIATIONS & VIOLATIONS IN SEVERITY LEVEL
FUNCTIONAL
AREA DEV V IV III II I
PLANT OPERATIONS 1 4 1
RADIOLOGICAL CONTROLS 2
MAINTENANCE / 1 16
SURYLILLANCE
SECURITY
ENGINEERING / TECHNICAL 2
SUPPORT
SAFETY ASSESSMENT / 7
QUALITY VERIFICATION
TOTAL 1 2 33 1
A total of seven automatic reactor trips occurred during the
assessment pericd, five above 15% power and two below 15% power. ~
No
manual trips were initiated and no trips occurred with the unit
subcritical. In general, these reactor trips occurred during power
esca11ation activities ano were followed by extended periods cf
continued operation. The trips are described in more detail below:
May 19,1988 - Unit 2 tripped from 73% pcwer due to a steam / feed
flow mismatch coincident with low steam generator level. This
situation occurred due to maintenance being performed concur-
rently on two p'ieces of equipment which together could cause a
reactor trip (one channel of steam generator level indication to
replace an unqualified splice and the #3 heater drain tank level
controller which resulted in plant oscillations).
May 23,1988 - Unit 2 tripped from 70% power due to low flow on
RCS Loop #4. This situation occurred due to a personnel error
while performing a surveillance on the Icop #4 flow transmit-
ters.
June 6,1988 - Unit 2 tripped from 98% power on steam / feed flow
mismatch coincident with low level in li4 steam generator. The
trip occurred while performing a surveillcrce on the feedwater
regulating valves and resulted because a diode was missing in
the block circuit.
_ _ _ _ _ _ _ _ _ _ _ _ _ - -
<
'
, *:
e
- 64
June 8, 1988 - Unit 2 tripped from 12% power on low-low level in
- 2 steam generator due to an operator error when placing the
feed pump controller in the automatic position resulting in
steam generator level oscillations.
June 9, 1988 - Unit 2 tripped from 20% power on low-low level in
- 2 steam generator due to feedwater heater isolations which
caused feed flow and steam generator level transients.
November 18,1988 - Unit 1 tripped from 72% power due to an
electrical ground in the main generator which tripped the main
turbine.
December 26,1988 - Unit 1 tripped from 75 power on low-low
level in #4 steam generator. The trip was caused by a series of
events that started with a manual trip of the main turbine due
to generator seal rubbing. After the turbine trip, steam
generator level was controlled using manual feedwater control
which resulted in a feedwater isolation from high-high level in
- 2 steam generator followed by the reactor trip on low-low *
level
in #4 steam generator.
I. Effluent Release Summary
1985 19.86 1987
Gases (Curies) (Curies) (Curies)
Fission and Activation
Gases 4.57 E+03 1.21 E-00 0.0
Halogens and
Particulate 6.63 E-03 1.56 E-03 5.04 E-04
Liquids
Fission and Activation
Products 2.08 E 00 1.65 E-01 4.66 E-01
Tritium 6.33 E+02 1.72 E+02 1.19 E+02
J. Acronyms
ALARA - As-Low-As-Reasonably-Achievable
ASME - American Society of Mechanical Engineers
ANSI -
American National Standard Institute
ANI -
American Nuclear Insurer *
AVO -
Assistant Unit Operator
AVT -
All Volatile Treatment
CAQR - Condition Adverse to Quality
CCW -
, Component Cooling Water
.
, _ _ . _ . _ _ _ _ _
_ _ _ _ .
, .
-..
.
.
!p .
c 65-
'
CEG - Contract [ngineeringGroup.
'
' NPP.- -
Nuclear Performance Plan
'DBVP - Design Easeline Verification Program
DNE. - Division of Nuclear Engineering
EA - Escalated Enforcement Action
Emergency Core Cooling-System
~
ECCS -
ECP -
' Employee Concerns Program
.ECTG - Employee-Concerns Task Group
EDG - Emergency Diesel Generator
E0P - Emergency Operating Procedures
EP -
L EPRI. -
Electric Power Research Institute
EQ -
Environmental Qualification
ERCW - ' Essential Raw Cooling Water
, FT -
Flow Transmitter
- GET. - General Employee Training
GL - Generic Letter
HP - Health Physics
IDI - Integrated Design Inspection
INP0 - Institute for Nuclear Power Operations
IR- - Inspection Report..
ISEG - Independent Safety Engineering Group
ISI. - Inservice Inspection
IST - ' Inservice Testing
LC0 - Liraiting Cordition'for Operation
.LER
- Licensee Event Report
'MIC - Microbiologically Incuced Corrosien
MILES -
Multiple Integrated Laser Engagen.ent System
MOVAT - Motor Operated Valve Actuators
MSIV -
NMRG - Nuclear Maintenance Review Group
NOUE -
Notice of Unusual Event
NRC - Nuclear Regulatory Commissior..
.NRR - Nuclear Reactor Regulation
NSRB - Nuclear Safety Review Board
OPDT - Over Power Delta Temperature
OSP - Office of Special Projects
OTDT - Over Temperature Delta Temperature
PM -
Preventive Maintenance
PMT - Post Modification Testing
PORC - Plant Operations Review Ccmaittee
PWR - Pressurized Water Reactor
QA - Quality Assurance
QMDS - Q6alified Maintenance Document System
QVI - Ouality Verification Inspection
RII -
Region II
RCA -
Radiation Centrolled Area
RHR -
RIP - Replacement Items Program
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ - _ _ _ _ _ - - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ -
( ,. . _ _ - _ _ _ _ _ _ _ _ . _ _ _ - . - _ . _______ _
ff jr , y
'
- 4
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66;
,
RTD- -- Resistance Temperature Device
SALP.: - Systematic Assessment of Licensee Performance
SG0G- - Steam Generators Owners Group
SI' -- Surveillance Instruction
. SNPP - Sequoyah Nuclear Performance Plan
. 501 .
System Operating Instruction-
' TACFs
.
-
' Temporary Alterations
' TDAFW- - Turbine Driven Auxiliary Feedwater Pump
TS . Technical Specifications
TSCR - Technical Specification Change Request
TVA' - Tennessee Valley Authority
TVAPD - 'TVA Projects Division (NRC)
UHI - Upper Head Injection
VCT- - Volume' Control Tank
.
I
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,
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