ML20151Y118
| ML20151Y118 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 08/17/1988 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20151Y090 | List: |
| References | |
| 50-334-87-99, 50-412-87-99, NUDOCS 8808260235 | |
| Download: ML20151Y118 (47) | |
See also: IR 05000334/1987099
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U. S. NUCLEAR REGULATORY COMMISSION'
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. REGION I
SYSTEMATIC ASSESSMENT OF. LICENSEE PERFORMANCE
. REPORT 50-334/87-99
REPORT 50-412/87-99
DUQUESNE LIGHT COMPANY
BEAVER VALLEY POWER STATION, UNITS 1 AND 2
'ASSESSMFN "RIOD: Unit 1: March 16, 1937 - May 31, 1938
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Unit 2: March 1, 1987 - May 31, 1988
1- ' BOARD MEETING DATE: . July 15, 1988
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8808260235
PDR 8808ADOCK 33000334
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TABLE OF-CONTENTS
PAGE
.I. INTRODUCTION . . . ..................... .- 1
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A. Licensee Activities . . . . . . . . . . . . . . . . . . 1
B. Direct Inspection and Review Activities . . . . . . . . 2-
II. ' SUMMARY OF RESULTS . . . . . . . . . . . . . . . . . . . . . 4
A. 0verview . .. .................... -4
B. Facility Performance' Analysis-Summary . . . .. . . . . *
C. Unplanned Shutdowns, Plant Trips and Forced Outages . . 6
III. CRITERIA . . . . . . . . . . . . .............. 8
IV. PERFCRMANCE ANALYSIS . . . . . . . . . . . . . . . . . . . . 10
A. Plant Operations. . . . . . . . . . . . . . . . . . . . 10
B. ~ Radiological Controls . . . . . . . . . . . . . . . . . 13
C. Maintenance . . . . . . . . . . . . . . . . . . . . . 18 ,
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D. Surveillance. . . . . . ................ 21=
E. Emergency Preparedness. . . .............. 24
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F. Security. ....................... 26 4
G. Engineerinp/ Technical Support . ............ 29 '
H. Safety Assessment / Quality. Verification. . . . . . . . . 32.
I. Preeperational and Startup Testing .....s. . . . 36
J. Training Programs . . . . . . ............. 40
V. SUPPORTING DATA AND SUMMARIES ............... 42
/.. Enforcement Activity. ................. 42-
B. Inspection Hour Su.nmary . ............... 43 ;
C. Licensee Event Report Causal Analysis . . . . . . . . . 44
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I. INTRODUCTION
The Systematic Assessment of Licensee Performance (SALP) is an integrated
NRC staff effort to collect the available observations and data on a
periodic basis and to evaluate licensee performance based upon this infor-
mation. SALP is supplemental to normal . regulatory processes used. to
ensure compliance with NRC rules and regulations. SALP is intanded to be-
sufficiently diagnostic to provide a rational basis for . allocating NRC
resources and to provide meaningful guidance to the' licensee management to
promote quality and safety of plant operation.
An NRC SALP Board, composed of the staf f members listed below, met on
July 15, 1988, to review the collection of_ performance observations and
data to assess the licensee performance in accordance with the guidance
in NRC Manual Chapter 0516, "Systematic Assessment of Licensee Perform-
ance". A summary of the guidance. ano evaluation criteria is provided in
Section III of this report.
This report is the NrC's assessment of. the licensee's safety perfo'rmance
at Beaver Valley Power Station Unit 1 for the period March 16, 1987, to
May 31, 1988, and at Unit 2 for the period March 1, 1987, to May 31, 1988.
The SALP Beard was composed of:
W. "ane, Director, Division of Reactor Projects (DRP) and SALP Board
Chairman
G. Sjoblom, Acting Director, Division of Radiation Safety and Safeguards
(DRSS)
J. Stolz, Director, Project Directorate I-4, Office of Nuclear Reactor
Regulation (NRR)
J. Wiggins, Chief, Projects Branch No. 3, DRP
J. Durr, Chief, Engineering Branch, Division of Reactor Safety (DRS)
L. Tripp, Cnief, Reactor Projects Section 3A, DRo
P. Tam, Licensing Project Manager, NRR
J. Eeall, Senior Resident Inspector
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A. Licensee Activities
This assessment pariod started with Beaver Valley Unit 1 operating midway
through the sixtr fuel cycle and Unit 2 in the final stages of pre-
operational testing. After the licensee integrated Unit 2 areas into the
Site Security Plan on April 13, 1987, Unit I was shut down and the wall
separating the twe control rooms was removed thus establishing a joint
'n i t 1 - Unit 2 control room. On May 16, 1987, Unit 2 completed the
/ ament, announced two months earlier, of the original ball-type main
isolation valves with valves of a more conventional design. On
May 28,1987, Unit 2 received a low power operating license (0L) and com-
pleted initial core load on June 1,1987.
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Unit I restarted on May 31, 1987, and operated continuously, with the
exception of hardware-caused trips on June 1 and June 9, as sunmarized in
Section II.C until the start of the sixth refueling outa w on December 11,
1987. The 185-day continuous run established a new site record surpassing
the previour longest run of 104 days. Balance of plant (80P) component
failures caused power reductions on three occasions but, in each case, the
licensee was able to effect repairs and return to full power. 7
Unit 2 achieved initial criticality on August 4,1987, and on August 14,
completed low power physics testing and received a #ull power OL. Unit 2
was first synchronized to- the grid for power operations on August 17,
1987. T"e startup test program was completed during the next three montSs
and included plant tranA ent tests such as load swings and trip tests frc.m
power such a: the loss of offsite power test Unit 2 entered commercial
operation on November 17, 1987.
Unit 2 experienced three reactor trips af ter commercial operation. Trip
experience during startu, testing is discussed in Section IV.I. The 'irst
trip occurred on November 17, 1987, just hours af ter entering commercial
operation and was caused by a technician inadvertently turning a turbine
rotor position module off, then on again, which produced a spurious
turbine trip. The reactor also tripped and offsite power motorized the
main generator through the onsite buses causing a brief loss of offsite ,
power as the breakers for site transformers tripped on overcurrent. The
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other two trips resulted from the loss of the 2A 4-kv bus from different
component failures on January 27, 1988 and on April 4. -1988; in each care
the resulting loss of the A reactor coolant pump (RCP) caused a 'ow
reactor coolant system (RCS) flow trip.
Unit 1 began the sixth refueling outage on December 11, 1987, and was
returned to service or March 2, 1988. During the outage, all thise steam
generators received 100*f tube inspections, three feedwater elbows were
replaced, and a reactor vessel thermal shield bolt was replaced. Unit 2
entered a brief maintenance outage following the January 27, 1988, trip
for a license-required first cycle snubber inspection. While cooling
down, a loss of Unit 2 :ontrol room annunciators occurred due to a fire in
an electrical cabinet which resulted in the declaration of an alert.
Annunciation was restored and the alert was terminated within four hou,'s.
Unit 2 was restarted on February 12, 1988, and placed on the grid or.
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February 13, 1988. Unic 2 tripped on April 4,1988, and was returned to
the grid on April 15, 1988.
At the end of the assessment period, both units were at 100*4 power and had
been operating continuously for 91 and 57 days respectively.
B. O_irect Inspection and Review Activities
At the beginning of the period, one NRC senior resident inspector and one
resident inspector were assigned to each Beaver Valley unit. After Unit 2
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received a full power operating license, completed startup testing and
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entered commercial operation, the NRC resident staff was reduced to one
. senior resident inspector and one resident ' inspector for 'the two . unit -
site. .- The ' total NRC inspection effort ~ for: the period was 10,650 hours0.00752 days <br />0.181 hours <br />0.00107 weeks <br />2.47325e-4 months <br />
(8,646 annualized). with a distributin in the various functional areas as
shown in V.B._ Over 5,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of-. inspection were associated with Unit 2
due - to ' extensive NRC coverage.- of Unit 2 preoperational ~ and startup
testing.
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Several . major NRC team inspections were . conducted at . Unit .2 during this
period -including the Emergency Preparedness Implementation Appraisal
-(March 3-7, 1987),- the Proposed Technical' Specifications Review (March 30
- April 10.1987), As-Built Verification (March 16-26,1987), Full Power
Operations Readiness (July 31 August 7,1987), .and Loss of Of fsite Power
Review - (November 18-20,1987). Unit I was reviewed by an NRC inspection
team using PRA principles (March 21 - April '1,1988). An NRC Emergency
Prepared 6ess Inspection Team observed the site annual. emergency exercise
on September 22, 1987.
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II. SUMHARY OF RESULTS
A. Overview
Continued overall improvement in the level of performance was demonstrated
during this assessment period despite increased pressures of starting up
Unit 2. Th licensee successfully. integrated Unit 2 into the site secur-
ity plan while maintaining program qu'ality and effectiveness. Startup
testing at Unit 2 was' accomplished during this period in a well control-
led, systematic manner with excellent interfaces between test and opera-
tiors personnel. In particular, the performance of the operation'. - staffs
at both units throughout this period was strong in that it was nearly
error free with timely apprcpriate actions on several occasions that pre-
vented additional plant challenges and trips. Continued strong perform-
ance was observed in the area of Emergency Preparedness.
A high level of management involvement -in day-to-day activities was evi-
dent. Weekly Unit 2 onsite mcetings were attended by the Chairman of the
Board through the completion of startup testing demonstrating active
involvement of senior corporate management. Further, several -licensee
initiatives have been effective in addressing or anticipating problems.
These initiatives included a task force to modify / replace the Unit 2
MSIVs, a task force to address Unit 2 recirculation spray system heat ex-
changers' fouling, and the Unit 2 self assessment during startup testing.
In addition, a program to conduct safety system #unctional evaluations
(SSFE's) was initiated on Unit 1. The Auxiliary Feedwater System SSFE was
completed cnd the preliminary results were _ reviewed near the end of the
period,
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Notwithstanding the generally streng overall performance, some areas where
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improvements are needed were evident. More management attention to the
ALARA program including increased staffing has the potential to reduce
exposure for major tasks in high radiation fields. Also, better configur- {
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ation control during high activity periods and improvements in post-main-
tenance testing are needed in order to achieve consistent high performance
levels. Procedural deficiencies and weaknesses were noted in several
areas and represent a generic problem. They contributed to a reactor
trip, inadvertent ESF actuations and failures to return systems to the
proper alignment following surveillances. Numerous deficiencies and
inconsistencies including human factors deficiencies were evident in i
emergency operating procedures. Finally, performance of candidates in
operator requalification examinations administered by NRC represented a
significant weakness during this period.
Overall, although there were some noted weaknesses that require prompt
licensee management attention, the performance of both units was con-
sidered good. Performance is especially noteworthy given the stress pre-
sented to the licensee by the completion of startup activities for Unit 2.
The programs in place have set the stage for continued improvement in the
overall operation of the facility.
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8. Facility Performance Analysis Summary
Last Period This
Functional Area Unit 1 Unit 2 Period Trend
Plant Operations 2 -
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Radiological Controls 2 -
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Maint. nance 2 -
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Surveillance 2 -
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Security 1
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Engineering / Technical
Support 2 -
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Safety Assessment / Quality
Verification 2 2 2
Preoperational and
Startup Testing -
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Training Programs - -
3 Improving
The following were not treated as separate functional areas in this I
assessment. Relevant insights have been included in the above areas.
Fire Protection and
Housekeeping 2 2
Refueling and Outage
Management 2 -
Licensing Activities 2 1
Training and Qualification
Effectiveness 2 2
Construction -
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Operational Readiness -
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C. Unplanned Shutdowns, Plant Trips and Forced' Outages
Power
Date Level Root Cause Functional Area
Unit 1
6/1/87 95% ' Material Failure Maintenar,ce
Description: During the performance of a surveillance test to troubleshoot a
low EHC control oil pressure, oil leakage past a cup valve and i
trip latch resulted in~ reaching the low control oil pressure.
Automatic turbine / reactor trip. '
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6/9/87 33% Material Failure Engineering /Tcch Support.
Description: While initiating a power ascension af ter completing feed regula-
ting valve repairs, several control rods dropped into the ,
reactor core, resulting in a high negative neutron flux rate
automatic reactor / turbine trip. The rod drop was due .to a
failed electronic card in the rod control system. The root
cause of the failure was recurrent overheating of the red con-
trol cabinets due to inadequate cooling air flow.
2/19/88 0% Prrcedural Inadequacy Surveillance
Description: Reactor trip on low-low steam generator water level due to the
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failure to return the reactor trip breakers to the as-found <
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position. Operato- error contributed in that "dummy" level
signals were not inserted to bleck a trip signal.
Unit j
8/5/87- A total of 16 trips were experienced between initial criticality i
11/17/87 and commercial operation. Six trips were the result 7of -equip- !
ment failure; five occurred during testing, some of which. were I
not unexpected; three were attributed to design problems; one to i'
' personnel error and one to procedural deficiency. Only one
recurrent trip cause (equipment failure) led. to- two trips.
11/17/87 98% Personnel Maintenance
Description: An automatic turbine / reactor trip and brief loss of off site
power occurred due to a voltage spike .to the turbine thrust
bearing wear trip circuit. The spike was the result of an
inadvertent bump of a turbine rotor position module power supply
switch by a technician performing work on adjacent. equipment.
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Unplanned Shutdowns, Plant Trips and Forced Outages (Continued)
Power
Date Level Root Cause Functional Area
1/27/88 100*; Random Material Failure --
Description: Ar. automatic reactor / turbine trip occurred due to low RCS flow.
Within milliseconds af ter securing a service water system pump,
a 4 kV bus overcurrent trip occurred which resulted in the loss
of the "A" reactor coolant pump.
4/4/88 100% Material Failure --
Description: An automatic reactor trip occurred due to low RCS flow when a
reactor coolant pump auto-tripped during the performance of a
balance of plant surveillance test. During the test, a relay
failed to block an undervoltage signal resulting in several
motor loads (including the "A" RCP) isolating from the 4-kv bus.
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III. CRITERIA
f Licensee performance is assessed in selected functional areas, depending
on whether the facility is in a construction or operational phase. Func-
tional areas normally ' represent areas signi ficar.t 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. Staf fing (including management); and
7. Effectiveness of training and qualification program.
On the basis of the NRC assessment, each functional area evaluated is
rated according ' three performance categories. -The definitions of these
performance categories are as follows: '
Category 1. Licensee management attention and involvement are readily
evident and place emphasis on superior performance of nuclear safety or
safeguards activities, with the resulting parformance substantially ex-
ceeding regulatory requirements. Licensee resources are ample and effec- ,
tively used so that a high level of plant and personnel performance is ;
being achieved. Reduced NRC atter. tion may be-appropriate. !
Category 2. Licensee management attention to and involvement in the per-
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, formance 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 reasonably allocated so
that good plant and personnel performance is being achieved. NRC atten-
tion may be maintained at normal levels.
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Category 3. Licensee management attention to and involvement in the per-
formance of nuclear safety or safeguards activities are not sufficient.
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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 attention should be increased above
normal levels.
TN SALP Board may assess a functional area to compare the licensee's
performance during the last quarter of - the assessment period to that
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during the entire period- in order to determine the recent trend. The
SALP trend categories are as follows:
Improvirg: Licensee performance was determined to be improving near the
close of the assessment period.
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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. '
A trend is assigned only when, in the opinion of the SALP Board, the trend'
is significant enough to be considered indicat1ve of a likely change in -
the performance category in the near future. For example, a classifica-
tion of "Category 2, Improving" indicates the clear potential for "Cate-
gory 1" performance in the next SALP period.
It should be noted that Category 3 performance, the lowest category,
represents acceptable, although minimally adequate, safety performance.
If at any time the NRC concluded that a licensee was not achieving an ade-
quate level of safety performance, it would then be incumbent upon NRC- to
l take prompt appropriate action in the interest of public health and
safety. Such matters would be dealt with independently from, and on a
3 more urgent schedule than, the SALP process, i
It should also be noted that the industry continues to be subject to
rising performance expectations. NRC expects licensees to use industry-
wide and plant-specific operating experience actively in order to effect
performance improvement. Thus, a licensee's safety performance would be-
expected to show improvement over the years in order to : maintain
consistent SALP ratings.
Further, in this assessment, Training Programs is evaluated a's a separate
functional area instead of combining its assessment with engineering
activities. This approach was agreed to by the SALP Board in order to
more clearly focus licensee attention toward needed improvements in the
licensed operator training area.
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IV. PERFORMANCE ANALYSES
A. Plant Operations (3388 hours0.0392 days <br />0.941 hours <br />0.0056 weeks <br />0.00129 months <br />, 32%)
1. Analysis
The previous assessment for Unit 1, evaluated as Category . 2, noted im-
proved performance in the overall. conduct of operations with good and
improving professionalism, active first-line supervision, and senior man-
agement involvement. There were seven plant trips during the previous -
period. Recurrent electronic equipment problems led to two plant trips
due to vital bus losses and nine shutdowns.or power reductions were caused
by balance of plant'(BOP) pump or feedwater control valve (FCV) problems.
Unit 2 was not . previously rated in this area. The current assessment
includes Unit 2 operations since entering commercial operations.
Continued improvement was observed in this area for Unit I during the -
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period. Two reactor trips were experienced during power operation, both
caused by hardware failures. Another trip occurred while the unit was shut
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down during the refueling outage caused by a procedural deficiency and a-
weakness in configuration control. . Unit 1 experienced ' both trips from
power in early June during the first 10 days af ter startup following con-
trol room modifications. The first trip was caused by an EHC valve leak
which dropped EHC +.urbine oil pressure and caused a turbine trip. .The
second trip was due to an electronic card failure which caused multiple
dropped rods and a negative flux rate reactor trip. Three reportable
events were attributable to Operations personnel during the period . (in-
ciuding Unit 2 following commercial operation), all of which involved . tag-
ging out or restoring equipment to service. The absence of plant trips or
significant operational events due to personnel errors' is attributed to -
increased licensee emphasis on problem analysis and management attention
to identification of root causes.
Unit 1 experienced four power reductions caused by B0P components, two
from feedwater control valve (FCV) problems and two from feedwater heater
drain system repairs. This represents a significant improvement from nine
such reductions last period and twelve the. period before and reflects in-
creased licensee attention to B0P maintenance and reliability. Histori-
cally, the FCVs have exhibited substantial noise, vibration and displace-
ment during power operation, .and FCV problems have caused many of.the past
power reductions. Modifications completed late in this period appear to
have nearly eliminated these visibie indications of accelerated FCV wear
and no FCV problems occurred during the three months of sustained power
operation after the sixth refueling outage.
Unit 2 entered commercial operation on November 17, 1987; operational
, experience prior to that data is assessed in the Preoperational and Start-
up Testing functional area (IV.I). An NRC Special Assessment was conduc-
ted from August 4,1987, to September 11, 1987, which concluded that -the
licensee had demonstrated very good operational performance.
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Five hours after entering commercial operation, Unit 2 experienced a tur-
bine trip from full power due to a spurious signal generated by a voltage
spike following a technician's inadvertent-toggling a-turbine rotor posit-
ion power module switch. The trip initiated a complex seqtence of events
which . led to a 17-second loss of offsite power. Licensee management was
closely . involved with the troubleshooting and corrective action planning.
The licensee's staff demonstrated excellent knowledge of the complex tech-
nical issues and design changes needed to ' prevent recurrence. A strong
safety emphasis was evident as the licensee methodically and unhurriedly.
studied the event and completed necessary design modifications prior to
restart.
Unit 2 experienced two additional reactor trips both caused by the loss of
a 4-kv bus (and attandant loss of a RCP) due to unrelated hardware fail-
ures. The first occurred on a spurious overcurrent signal after securing
a service water pun.c; the licensee was unable .to reproduce the event and
elected to replace the candidate relays and sent them to an offsite labor-
atory for further study. The second bus loss was due to a contact failure
during a BOP surveillance test. Operator responses to the trips were
excellent and the licensee's post-event troubleshcoting thorough.
On January 28, 1988, erratic control room visual window display and . horn
operation occurred while Unit 2 was shut down for a planned. maintenance
outage. The operators immediately diagnosed the annunciator problem to be
originating in specific remote cabinets and, within three minutes, re-
sponded to the correct location. A small fire was found in one cabinet
and promptly extinguished. The licensee's actions during the event,
especially the performance of the operators, was considered to be a not-
able strength.
Prompt and accurate operator response to plant transients during this
period avoided several safety system challenges or plant trips, especially i
during Unit 2 startup testing. . Control room professionalism and operator
attitude were very good, even-during high activity periods such as startup
testing and major outages. Early in the period, prior to Unit 2 license
receipt, Unit 1 entered a five week outage to facilitate removal of a con- I
structinn wall within the Control Building which divided the control room
into separate areas for each unit. This - activity was well planned and
resulted in a control room facility with safety grade ventilation avail- l
able from either unit. !
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The licensee's fire protection program was considered adequate with good l
site fire brigade training and off site backup capability.
In summary, continued sound performance in Unit 1 operations was observed
with few reactor trips and power reductions. Unit 2 operational perform-
ance was also very good, especially in comparison with other first cycle
units. Notable strengths were observed in management involvement, oper-
ator event response and problem solving. The absence of any significant
operational problems attributed to personnel performance difficulties
demonstrated the effectiveness of licensee controls in this area.
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2. Conclusion.:
Category
3. Board Recommendations:
None
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B. Radiological Controls (874 hours0.0101 days <br />0.243 hours <br />0.00145 weeks <br />3.32557e-4 months <br />, 8%)
1. Analysis
The Unit 1 Radiological Controls and Chemistry Program was rated Category
2 last period. A need for improvement in management oversight of 'activ-
ities -and improvement in the corrective action system was identified. The
Unit 2 program evaluation war included in the Operational Readines; func-
tional area last assessment period and was rated Category 2 with no radio-
logical controls weaknesses. Ongoing licensee efforts to extend the radi-
ation safety program to support combined unit operations were good.
Radiation Protection
Licensee efforts to ensure acceptable transition from single to dual unit
operation was apparent, well planned and implemented. These efforts
included appropriate increases in staffing and comprehensive training of
personnel on dif ferences between the two stations. Staffing was adequate
to support routine radiation protection activities. The licensee also
purchased and placed in service several whole bcdy centamination monitors
and whole body counters to enhance capabilities in this area.
Overall communications (e.g., between operations and radiation safety
personnel) were good; however, some communications weaknesses between the
radiation safety and security organizations at the beginning of the Unit 1
outage resulted in an initial shortage of contractor radiation protection
technicians to support the outage. Some deficiencies observed during the
outage (e.g., poor radiological posting and labeling and poor house-
keeping) were attributed, in part, to this shortage.
A well defined and adequate training and qualification program 'for radia-
tion protection personnel and radiation workers was established and imple-
mented. The contractor technician _ training program was of good quality. A
continuing training program was in place and implemented. Management at-
tention to this training was evident.
Licensee audits of-program implementation examined all appropriate areas;
however, audits were compliance oriented in nature. Technical specialists
were rarely used. 0A personnel experience in the area of radiation safety
was minimal. Consequently, evaluation of radiation safety program adequacy
l 'and performance relative to industry standards and performance was
limited.
Weaknesses in the routine internal self assessment program identified last
period (e.g., lack of formalization, trending, and evaluation) remain. An
additional concern identified this period was lack of long term corrective -
actions on some self assessment findings. Although self identifying of
problems by tFis routine program was an excellent licensee initiative,
lack of long-term corrective actions on self-assessment findings limited
the value in contributing to long-term program enhancement.
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Weaknesses in the area of self assessment were compensated for this
assessment period by the licensee's performance of an in-depth self
assessment using INP0 evaluation criteria. -Items for improvement were
included in a corrective action plan. The licensee's offsite review com-
mittee also reviewed iecent inspection findings in the area of radiation
protection to identify areas for improvement. These actions were con-
sidered good licensee initiatives.
High Radiation Area key control weaknesses identified -last period were
correctad. Radiological surveys to support on going work-were comprehen-
sive. A need for more aggressive oversight and control of major exposure
tasks and improvement in- the quality of procedures controlling these tasks
was identified by NRC during review of outage activities. There were
lapses in control of diving operations in that no one had been clearly as-
signed specific responsibility for monitoring the ' diver's position. Also,
weak procedures for control of steam generator entry coupled with poor -
oversight by supervision resulted in an. individual's 1000 mR dosimeter
going off-scale during a poorly controlled entry. Although no regulatory
overexposure resulted, the individual exceeded .his allowable administra-
tive exposure limit by 500 mR. Diving procedures for the reactor vessel
were improved to address ' NRC ' concerns. These weaknesses indicated the
need for additional licenses attention to control of personnel exposure.
A defined Internal Exposure Control Program was in place and implemented.
No significant individual intakes of radioactive material by personnel
occurred. Previously identified weaknesses with whole body counting equip-
ment were corrected by licenve purchase and placement in service of
state-of-the-art whole body counting equipment. A program to select per-
sonnel from among those werking on jobs with the pc tential for airborne
radioactivity intake for whole body counts in order to provide a second
-
-
check on the airborne radioactivity sampling and internal exposure control
programs was not in place.
Lack of confirmatory termination whole body counts was not in consonance
j
with general industry practice, and significant numbers of. personnel were
not provided confirmatory exit whole body counts as recommended by station
procedures. Licensee control of contamination and efforts to minimize
contaminated areas were good.
. Weakness in control of air samples continued. There was a failure of a
technician to noti fy supervision of unexpectedly high airborne radio-
activity concentrations during clean up of the Unit 1 reactor cavity.
Although licensee identified, there was a lack of timely corrective action
reflecting weaknesses in the program for corrective action and a lack of
appreciation of the significant airborne radioactivity levels identified )
(100 times aaxinum permissible concentration). Of particular concern was i
the fact that multiple supervisory personnel later signed o f acknowled- 1
ging the air sample results without taking any action on thern. This vio- l
lation was symptomatic of weaknesses in the program-for review of airborne
survey results. In addition, it reflected continuing weaknesses in the
control of air samples which was identified last period. i
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- - * . . - ~ . -,- -- + . - - . . _ , , - .s_..m. , , - - . - - - - - --- ,e--_- r , . - ~ .m- , -e-. -,,--,ys-
,_ _ . . . _
__
.
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. 15
Station aggregate exposure for the past five years compares favorable with
industry averages. This however is attributed to the licensee's lack of
performance of significant steam generator work. . Followup of previously
identified weaknesses ir. the ALARA area continue to indicate a' need for
additional oversight and emphasis on ALARA. Observations during the Unit
1 outage identified lack of ALARA reviews for some steam generator work,
lack of attendance at ALARA Review Committee meetings, weaknesses in ALARA
goals due .to lack of accurate person-hour estimates to perform work, lack
of a defined program to perform review of on going work from an ALARA
perspective and lack of sensitivity to ALARA by workers.
-General area radiation levels associated with steam generator work con-
tinue to be some of the. highest in the industry indicating some weaknesses
in licensee management of his radiological source term for steam generator
work.
Some weaknesses in licensee planning for emergent work was also identi-
fied. Licensee ALARA planning for steam generator work only considered
inspection of a single generator. The planning did not consider potential
emergent work on other steam generators. Additional steam generator . work
subsequently was required.
Despite these weaknesses, good ALARA performance by contractors was noted
on some major tasks (e.g. , reactor vessel flow baffle work and thermal
shield work). This work involved significant in vessel work. The licen--
see also removed a significant number of unnecessary snubbers thereby
reducing the need for performance of survefilances in radiation areas.
Staf fing in the ALARA area is considered weak. Although some individuals
provided technical support, one individual was assigned responsibility for
evaluating work packages, performing ALARA reviews, and performing in-
plant ALARA functions (e.g., worker briefings). This represents a weak-
ness in the staffing level to support activities in this area for two
units.
Licensee corrective action on NUREG-0737 post-accident sampling findings
were technically sound indicating a good understanding of the technical
issues.
Radioactive Effluent Controls and Radwaste Systems
The preoperational test programs for the Unit 2 effit:ent monitoring,
process sample stations, and radwaste systems were based on the FSAR and
appropriate procedures and overe good. Staffing was timely and generally
complete with little reliance on contractor personnel. The licensee
developed an adequate program for control of radioactive effluent from the
site (Units 1 and 2) which demonstrated a viable and sound- technical
approach. Also, the preoperational testing of the radiation monitoring
system was well planned with priorities assigned to support preoper6tional ]
and operational milestenes,
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. . . .
.
. .
. 16
Numerous minor abnormal gaseous and liquid releases of radioactivity
occurred early in the assessment period due to operator, surveillance, and
maintenance errors. The need for greater attention to detail during oper-
ation of radwaste equipment 'was indicated. The Radiological Controls
group. demonstrated the capability to comply with the Technical Specifica-
tion requirements during these abnormal releases.
Radiological Confirmatory Measurement
A confirmatory measurement inspection was performed using the NRC Region I
Mobile Laboratory. All split sample results were in agreement between the -
licensee and the NRC. The licensee had state-of-the-art gamma and ' liquid
scintillation counting systems which indicated management. support. Pro-
cedures were generally adequate; however, the licensee did not implement
certain aspects of the Laboratory Quality Control Program (comparisons of
inter- and intra-laboratory blind samples). Audits by QA group wers tho- '
rough and technically sound but one weakness noted was that audit person-
nel did not track the previously identified follow-up items thoroughly.
These problems were minor; the licensee had a generally sound program in
this area.
Transportation
The position of iransportation Supervisor was assigned the responsibility
for the maintenance of licenses and permits, compliance with applicable
procedures, regulations related to the receipt and shipment of radioactive
materials, and review and revision of the Process Control Program. How-
ever, this position, which was created in August 1986, had not been filled
at the end of this assessment period. Two violations were identified dur-
ing this period that might have been avoided had the position been filled.
Although the licensee had ar adequate transportation program, attention
should be focused on filling needed positions.
Summa ry
Although some new equipment was purchased and placed in service, perform-
ance in the area of radiation safety and transportation continued at es-
sentially the same level as last period. Licensee radiological control
personnel performance in the area of radioactive effluent controls was
generally strong. Station total personnel exposure has shown a decline-
over the past several years consistent with overall industry performance.
However, continued enhancement of worker consciousness.of ALARA and pro- !'
gram improvements in this area was warranted. Improvement in management
and supervisory oversight of major exposure tasks was similarly warranted.
The corrective action system, a previously identified area for improve-
ment, continued to need additional management attention.
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' 17
2. Conclusion:
Category 2
3. Board Recommendations:
Licensee:
Strengthen supervisory and management oversight and procedural controls
for significant radiological tasks Additional efforts are needed to
reduce personal exposure during future steam generator werk.
NRC:
None
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_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ . _ _ _ _ _ - _ - _ _ _ _ . _ ._ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. . . - -
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. 18
C. Maintenance (742 hours0.00859 days <br />0.206 hours <br />0.00123 weeks <br />2.82331e-4 months <br />, 7'J)
~1. Analysis
During the previous assessment period, Maintenance and Modification was
evaluated as Category 2 for Unit 1. Generally good control of preventive
and corrective maintenance activities was noted. This current. assessment
includes Unit 2 maintenance activities which were incorporated into the
common site programs when initial criticality was achieved (August 4, 1987).
Maintenance procedures and policies were typically followed well by sta . i
tion personnel. Maintenance goals had been_ established and the dates were '
being met within the tolerances established by the program. The backlog i
of_ maintenance tasks was well managed. In particular, it was noted that
the licensee had developed a thorough maintenance and test ~ program fo r.
electrical equipment, including battery chargers, batteries, circuit
breakers and transformers. '
'Considering the time period covered, there was a relatively low number of
problems attributable to personnel error. Three Unit 2 reactor trips
occurred due to error; one was attributed to failure to perform adequate
post-maintenance testing, another involved inadequate job preplanning and
the lack of attention to detail, and the third was caused by an accidental
bump of nearby equipment. Four ESF actuations occurred during maintenance
activities due to various causas, including improper use of available
equipment, technician failure to note the effect of work' activities on
associated plant equipment and deficient procedures. Generally,-mainten-
ance procedures were found to be technically so~und but required improved-
human factors considerations, especially those that involve - activities
that can result in plant trips or ESF actuations.
Maintenance personnel were trained to work on both units and were found
to be knowledgeable of station procedures and the tasks to which they were
-
assigned. Toward the end of the SALP period, the mechanical and elec-
trical maintenance training programs werc accepted and accredited by INPO.
The previous assessment noted that a list of personnel qualified to par-
form certain jobs was not maintained by the individual, departments, and
personnel were selected on an as-available basis by supervisors who were
familiar with the individual's qualifications. A minimum job training '
concept was implemented. Although the minimum job training lists were not
complete, updated lists were periodically distributed to supervisors to
assist them in selecting personnel to perform naintenance activities. The ,
current program appeared to be functiening properly in that the quality of
maintenance was generally good and in accordance with site procedures.
- ,
,
y -.v -- , ww - ,--e, -,e-,
.. - -
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. 19
Quality control involvement in maintenance activities was adequate. Qual-
ity control inspectors were' usually present during significant activities
and were performing in process inspections of ongoing maintenance work
activities. They were knowledgeable of the activities observed.
Day-to-day preventive and corrective maintenance o'f safety related com-
ponents received adequate preplanning and _ supervisory oversight. Daily
meetings provided a good mechanism through which proper coordination and
interfaces were established with the various station groups. Proper use
of clearances and . adequate interface among the' various station groups
(radiological control, quality control, etc.) necessary to accomplish
maintenance activities were observed in the field.
Previous assessments identified weaknesses in complying with administra-
tive requirements associated with complete maintenance work requests (MWR)
documentation. Improvements in this area occurred during this period,
with the exception of post-maintenance testing. The _ required post-
maintenance testing or reason for not performing testing were not always
identified on the MWR. In one example, a manual reactor trip. was required
due to a Unit 2 rod control system problem. The failure to test the sys-
tem properly following the associated maintenance troubleshooting activ-
ities resulted in a second . manual reactor trip due to - dropped control
rods. A similar example was the failure to test a liquid waste motor-
o, erated valve properly following maintenance resulting .in an inadvertent
liquid r31 ease. Root causes for the second event included improper main-
tenance and a breakdown in communication among the responsible station
groups. Additional management attention will be necessary to achieve a
better post-maintenance testing program.
Historical information in the maintenance database was very good. How-
ever, preventive maintenance trending at the site needs to be improved,
in that trending was found to be performed on a reactive rather than sys-
tematic basis. Managemant did not provide the staffing necessary to pro-
vide a thorough trending program even though plant performance personnel
had identified valuable information during several reactive trending
analyses.
For tha majority of the period, plant housekeeping during and following
the conduct of maintenance was weak. Areas were littered with tools, com-
ponent parts and debris. Additionally, unrestrained equipment, such as
ladders, gas bottles, and large tcol cabinets on rollers were often ad-
jacent to equipment important to safety. The. licensee developed detailed
guidance in the Maintenance Manual in an attempt to resolve -the concerns.
While improvements were continuing, individual deficiencies continued to
be identified to the licensee for resolution. Aggressive management over-
sight was not apparent in this area for the majority of the assessment
period.
. ,. - - - - .- - . - - . .
.- , - - -
. . . __ .. _ _. . _ . _ . . . ._.
'
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20
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In ' summary, . licensee ~ activities associated -with. preventive and corrective
maintenance were generally well controlled. The. relatively : low number of
unnecessary challenges to safety equipment reflected overall satisfactory
technician training and adequate procedures. Improvements in the areas-of
housekeeping, post-maintenance testing, and; procedures are necessary if
improvements are to be achieved in the maintenance program.
2. Conclusion:
.
Category 2 ;
.
3. Board Recommendations:
Licensee:
Implement a program to improve procedures, post-maintenance testing and
trending.
NRC:
None
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. 21 :
D. Surveillance (790 hours0.00914 days <br />0.219 hours <br />0.00131 weeks <br />3.00595e-4 months <br />, 7*4)
1. Analysis
During the previous assessment period, Surveillance was evaluated Category -
2 for Unit 1. Operational Readiness Category 2, Improving was evaluated
for Unit 2. While a surveillance program- that was generally functioning
well was noted, concerns were identified with respect. to reviews of test'
data for reasonableness, several missed surveillance tests, and the con-
tinued need to strengthen the 18-month operations surveillance test system
alignment methodology. This current assessment includes _ Unit 2. surveil- ,
lance activities which were incorporated into the - common site programs '
when initial criticality was-achieved (August 4,1987).
The last assessment noted that Unit 2 operational surveillance tests were
incorporated into the routine surveillance schedule once a system was
turned over to the station to maintain operability. This process was
continued and was a licensee strength, demonstrating that the licensee
placed cunsiderable effort in preserving plant equipment. There was one
reactor trip and about 15 additional reportable events that occurred
during surveillance testing activities. The majority of the reportable
events were due to inadequate procedures. The. number of missed
surveillance tests occurred at about the same rate as during the last SALP
period.
The licensee maintained a strong reliance on individual surveillance test
coordinators who were accountable for the administrative implementation of
the program. Each station group that performs surveillance tests was ;
responsible for the overall coordination arid control of their. respective !
portions.of the surveillance program. The licensee maintained an informal
Technical Specification (TS) and procedure matrix which was a computerized ,
cross reference of plant procedures and TS. The matrix was revised
annually and provided a mechanism through which identification and cross
referencing of procedures could be accomplished and was. generally used
effectively for a variety of administrative purposes. At the end of the
period, licensee efforts were initiated to provide a more current matrix
for use by surveillance test coordinators.
The four missed Technical Specification-required surveillance tests were
all caused by different types of administrative / personnel errors. In-
creased attention to detail with respect to communication among the var-
ious departments may be necessary.
Staffing for each of the surveillance programs and the training and qual-
ifications of radiological control, operating and test personnel with
respect to surveillance testing performance' were adequate. Preservice
(Inservice) Inspection staffing was improved by the addition of a Level
,
III and two Non-Destructive Examination (NDE) technicians. This permitted 1
the licensee to take over review responsibilities for NDE results. Inser- l
vice testing of pumps and valves was performed adequately although NRC '
identified some minor problems concerning procedural details. I
e
.
. .
. 22
One programmatic area needing further management attention was the control
of surveillance activities and adequacy of the associated procedures which
impact operability or challenge : 'ety systems. Three separate but
similar events occurred when surveillance activities were performed which
did not adequately return the systems to required positions or did not
verify Technical Specification requirements. Prior to initial entry into
Mode 4 (Hot Shutdown), the operational surveillance test procedure failed
to identify that the Unit 2 control room emergency bottled air pressuriza-
tion system actuating circuit was disabled. While Unit I was in a cold
shutdown condition following completion of a surveillance test, the tech-
nicians failed to return the reactor trip breakers to the as-found po-
sition. Subsequent drain down of a steam generator resulted in a low -
low level reactor trip signal and automatic opening of the reactor trip
breakers. The third event i nvol v.:d the performance of a surveillance
activity which lef t two high-high containment pressure bistables in a
different configuration than as-found renderine uo out of the four auto-
matic actuation channels for the containment spray system inoperable. For
the last two events, operator error and human factor deficiencies were
contributing factors. Site management hu recognized human factors con-
cerns to be a problem; however, aggressive resolution was not apparent as
a relatively la rge number of events were attributable to deficient
procedures.
The eddy-current testing of the steam generators during the Unit I refuel-
ing outage implemented an innovative approach in the data analysis in that
independent reviews were performed by different vendors. However, one
weakness in this method was that the different vendors did not use the
same terminelogy in reporting the results although this did not lead to
any problems. The licensee was responsive to the concerns associated with
the North Anna steam generator tube rupture. Special eddy-current inspec-
tions were performed and preventive tube plugging was implemented. To
provide a mechanism through which the failure of a tube susceptible to the
North Anna type f ailure could be identified (even if plugged), six tubes
were plugged with a standard plug in one end and a sentinel plug designed
to limit a leak to 300 gallons per day in the other end. With this tech-
nique, if any of these six tubes ruptured, the leak rate would increase by
300 gallons per day (below emergency shutdown limits) and allow an orderly
plant shutdown. Another example of the licensee's response to recent
industry experience was the performance of eddy current testing of all 50
in-core instrumentation thimble tubes. Incications were evaluated and
appropriate corrective actions were implemented. These actions repre-
sented good safety perspective and initiatives.
The results of secondary water chemistry control during the majority of
the period were excellent. Sodium, chloride, sulfates and silica were
generally below the values that could be determined by the on-line, state-
of-the-art equipment used for the analyses. The morpholine additions the
licensee performed appeared to make the blowdoien process more effective in
sludge removal. Close attention to secondary water chemistry as demon-
strated by the licensee should help to reduce steam generator tube degra-
dation and improve plant safety.
~
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. 23
In summary, the relatively low number of unnecessary challenges to safety
equipment reflected overall satisf actory technician training and adequate
procedures. The surveillance programs functioned adequately. Configura-
tion control, particularly during high activity periods, and procedural
adequacy were areas which required further management attention if the
surveillance test program implementation is . to be strengthened. Manage-
ment commitment to address potential safety issues from a technically
sound perspective was evident.
2. Conclusion:
Category 2
3. Board Aecommendations;
Licensee:
Cem> ~ ete review of procedures for human factors deficiencies, especially
those associated with outage recovery
NRC:
Nore
-_ _ -- - -
.
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24
E. Emergency Preparedness (447 hours0.00517 days <br />0.124 hours <br />7.390873e-4 weeks <br />1.700835e-4 months <br />, 4%)
1. Analysis
During the previous assessment period, licensee performance in this area
was rated Category 1. This was based upon exercise performance and the
licensee's own initiatives in routine emergency preparedness actisities.
Inspections of emergency preparedness activities included the Emergency
Preparedness Implementati:n Appraisal (EPIA) and three followup inspec-
tions prior to Unit 2 licensing. The annual emergency exercise (partial-
participatica) for both units wcs observed, and changes to emergency plans
and implementing procedures were reviewed. Response to the January 28,
1988 loss of annunciator event was also evaluated.
The EPIA performed on March 2-6, 1987, about 10 weeks prior to license
receipt, focused on the readiness to integrate the Unit 2 program into the
overall site and corporate emergency preparedness program. The EPIA
identified several program areas as incomplete or in need of correction
before readiness to receive the low power and full power licenses.
Followup inspections conducted in April through June 1987 trrcked
licensee progress in completing open items prior to full power licensing.
By June 1987, all items had been adequately addressed, an indication of
positive response to NRC initiatives.
Emergency response facilities were common to both units with the exception
of the control rooms. As a result of EPIA findings, Unit 2 control room
upgrades were made in communications capability, addition of protective
clothing, and improvements in security arrangements. Other changes to
facilities included enhancement of onsite and remote (of fsite) assembly
areas, and enlargement of the Radiological Operations Center (ROC). Capa-
bility of other facilities which include the Emergency Operations Facility
(EOF), Technical Support Center (TSC), and Operations Support Center (OSC)
were demonstrated in routine drills conducted at different times through-
out the period and deemed effective as emergency response facilities. Full
time site support staf f s were adequate to maintain effective onsite and
offsite activities associated with the program. This included permanent
emergency preparedness staff with additional support from the Operations,
Health Physics, and Training Departments.
During the partial participation exercise conducted on September 22, 1987,
the licensee again demonstrated an aggressive approach toward implementa- l
tion of the Emergency Plan and implementing procedures while maintaining a l
high level of emergency preparedness. NRC identified only minor exercise !
deficiencies in the areas of TSC information flow, handling of the
contaminated / injured individual, and functioning of the plant paging !
system. The licensee conducted an adequate self-critique by identifying '
deficiencies which occurred during the exercise and committed to take
actions to correct the deficiencies.
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.
. .
. 25
l
On January 28, 1988, a loss of. Unit 2 control room annunciators required
declaration of an Alert emergency classification. Onshift staff promptly -i
recognized the event, and after review of EALs, correctly classified the
event as an- Alert. Notifications of offsite authorities were performed
within the 15 minute requirement. The emergency response organization was
also notified while activation of the TSC, OSC, and ROC occurred. After
activation of local Emergency Operations Centers (E0C), coordination with
state and county representatives was closely maintained. Following event
termination, the licensee reviewed the event to assess -the response and
identify. actions t- be taken to prevent recurrence. Overall, the licensee
accurately and e fectively implemented the site Emergency Preparedness *
Plan in a timely manner. Furthermore, the licensee recognized the un-
-
'
1
realistic conservatism in the EAls associated with this event and appro-
priately revised the Emergency Plan prior to plant restart.
The interface between the emergency preparedness staff and licensee man-
agement was noteworthy. Upper level management was supportive in expe-
diting correction of weaknesses identified during the EPIA. This was evi-
denced by prompt resciution of all 26 EPIA concerns within approximately 4 '
months of initial NRC identification. The relationship between the licen-
see and offsite authorities continued to be -strong. Notification and co- ,
ordination with the States of' Pennsylvania, Ohio, and West Virginia, and +
counties of Beaver and Columbiana during the. loss of annunciatcr event
-
allowed the response to be carried out effectively.
In summary, the licensee successfully integrated Unit 2 into the site ,
Emergency Preparedness Plan in a timely . manner to support licensing. i
Excellent personnel attitude, management involvement and organizational
responsiveness continued to be demonstrated in day-to-day activities and '
l drills. Licensee overall performance was noted to be strong during the
'
January 28, 1988 Alert.
2. Conclusion: '
Category 1 ;
I
3. Board Recommendations: f
!
None
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. 26
- F. Security (433 hours0.00501 days <br />0.12 hours <br />7.159392e-4 weeks <br />1.647565e-4 months <br />, 4%) ,
,
1. Analysis
i
This 'is the first SALP of the combined Unit I and Unit' 2 security program ~ .
The two prcgrams were integrated early in this assessment period. ,
~
During the last assessment _ period, no major programmatic weaknesses were -
identified for Unit 1 'and a Category 1 rating was assigned. The 'func-
- tional area of- Security and Safeguards - w'as included in the Operational
Readiness portion of the previous _ Unit 2.SALP and that portion sas -as . ,
sigr.ed a ' Category 2 rating. A common concern in both the Unit i and Unit ,
2 assessments for the last period was the adequacy. of the licensee's pro- :
prietary security staffing level, . consisting of three full-time positions
at that time, to. provide the necessary effective oversight and control of
the contract security force for a two unit site, especially considering ,
the problems inherent.with the startup and integrating of the systems and '
equipment.
The 'icensee recognized and responded to the NRC concern about the poten- . '
tiai 'or problems with the then-existing proprietary staff and expanded l
the staff from three to eight full-time positions over this assessment
period. A training coordinator and four security shift supervisors were
added to the proprietary staff. The security shif t supervisors 'provided
around-the-clock shift . oversight of the security contractor. The expan- '
sion of the proprietary staff demonstrated management support and atten-
tion to the security program. The shift oversight function was imple- '
mented toward the end of the as.sessment period and its effectiveness has '
not been assessed by the NRC. .
At the start of the assessment period, the licensee experienced several
problems inherent with the startup of the new systems and equipment,. in- !
. cluding new security computers installed as part of combining Unit 1 and ,
j Unit 2. Contributing to the problems was the f act that there were more ;
than 3000 construction workers onsite completing work on lbit 2 at the '
time the combined security program was being made ' operational. The con- !
, tract security force was also working a larger amount of overtime at that
time to support Unit 2 construction activities and the preoperational
i
testing and calibration of the new security equipment and systems. Towards -1
the end of the assessment period, most of the integration, construction, '
l and new equipment problems had been resolved, the proprietary security
<
staff had been expanded and the security force overtime had been reduced
i to a minimum. Management's prompt action to resolve the problems encoun-
l tered demonstrated the licensee's intent to maintain an effective security i
l
'
program. Security management personnel continued to be actively involved
in industry groups engaged in nuclear plant security matters. This also
'
demonstrated program support from upper level management. ,
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27
About midway through the assessment period, the NRC identified concerns
about tha sparse maintenance support being af forded to Unit I security
equipment md the use of long-term compensatory measures for inoperative
equipment. The majority of the maintenance resources were being utilized
for o.erall Vait 2 preoperational activities. Senior management promptly
committed to review all the Unit 1 security maintenance concerns and tc
have all inoperable equipment repaired within 60 da T. This was accomp-
lished in the committed time period and the long-ta i compensatory meas-
ures were terminated. Subsequert inspections indicated that the mainten-
ance work vs very effective and that increased maintenance supprt was
continuing. This demonstrated senior management's responsiveness to NRC
findings; however it also indicated a previous lack of appropriate atten-
tion to corrective maintenance or escalation of maintenance problems to
prepar management levels to effect resolution. In either case, upper
leve management should have been alert for compensatory measures which
resu. sed from uttimely correcti,9 maintenance.
The training pr gram was administeaed by four fu. l-time, experienced in-
str ctors. In-depth lesson plans had been developed, were current, and
reflected the com.ni tme n t s in the NRC-approved security program plans.
Trainino facilities were professio al and instruct 0 tal aids were utilized
extensively. All security-related facilities, e.g., guard house, alarm
sta . ions and of fice areas, were well maintaineri, orderly and clean. Licen-
see oversight of the training program was provided through a proprietary
training coordinator and demonstrated .he licensee's intent to maintain an
effective and professional training program. Program implementing proced-
u es and instructions continued to be updated when required, based on
fedbacr. from training and security operations supervisinn. to provide the
nuity force with current, clear and c.oncis? directions. Members of the
security force were knowledgeable of their duties and responsibilities.
The high quality of the training program and *Se prc:edures and instruc-
tions was apparent from the relatively few personnel errc s during the
assessme7t period and was further evidence of management support and at-
tention to the program.
The turnover rate in the contractor security force remained low anc staff-
ing appeared to be sufficient, as indicated by the limited amount c' ver-
tin,e being worked at the end of the assessment period. Contractor ser-
visory and administrative staffitg was also sufficient for the current
work load. The licensee's oversight of the contract security force was
adequate to provide the licensee with necessary and current knowledge
regarding inram implementation. This was apparent by the licensee's
self iden* i- *e er*1 program deficiencies throughout the period. I
_ - - _ - - - _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _. \
. . - _~ . _ . -- . . .- -. .- - - , - -.
.
., . .
.
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. .28
.
The _ licensee submitted 30 event reports under 10 CFR 73.71(c). This
relatively_ large number of reports was due to several factors: (1) a
revision to the NRC reporting requirements in October 1987; (2) very con -
servative reporting prn tices on the part of the licensee, (3)-the startup-
of new systems and equipment; and (4) the integration of the 8) nit 2 sys-
tems with Unit 1. A detailed review of the event reports-by NRC indicated !
that only ten of the events had to be reported under the current NRC
reporting requirements. Of these ten events,. three involved guards who ,
were inattentive to duties. These events occurred during the period when
large amounts of overtime were being worked by the ' ecurity force t.o sup-
port Unit 2 construction activities and the installation and testing of
_
new security equipment. None of the events constituted a security vulner-
abi 't i ty. Inmediate and appropriate compensatory measures were implemented
in each case and corrective actions appear to have been effective. There
were no such incidents during the last half of the assessment period.
,
During the assessment. period, the licensee trant;mitted four revisinns; to
the Security Plan under the provisions of 10 CFR 50.54(p). Two of these '
.
revisions were found acceptable, the others are currently under review.
The re is_ ions were adequately sumcarized, appropriately marked to facil-
itate the NRC review, and of good quality. This ras indicative of work by
~
personnel who were knowledgeable of NRC sccurity requirements ard program
objectives and management attention to submittals to the NRC. -
In summary, the licensee has continued to implement an effective and qual- '
ity security prograia. The proprietary security organization has been
expanded and significant capital resources have been expended to _ upgrade
security systems and owipment. Problems with the integration of Unit-1 r
and Unit 2. encountered early in the assessment period received management !
attention and were resolved effectively. The licensee continues to be ;
4 responsive to NDC initiatives, however, better long range planntag is war- !
- ranted.
1
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2. Conclusion:
Category 1 -
3. Board Rec:mmendations:
None
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G. Engineering / Technical Support (1065 hours0.0123 days <br />0.296 hours <br />0.00176 weeks <br />4.052325e-4 months <br />,10%)
1. Ar.:lysi s
During the previous assessment, Unit i received a Category 2 rating in
Engineering Support. Strengths were noted in the on-site locat;on,
day-to-day involvement and increasing emphasis on problem ino.stigation;
weaknesses were identified in timeliness to respond to station requests,
corrective actions to long-standing problems and program oversight.
During this period, this functional area addresses design of plant
modifications, training and engineering / technical support for all plant
activities.
Training programs which would normally be assessed within this functional
area has been addressed separately in Section IV.J.
The licensee was in a transition period in an effort to combine the engi-
neering functions for both Units 1 and 2. At the end of the assessmert
period, engineering effort was about equally divided between licensee
personnel and the original Architect /Enginear for the station, Stone and
Webster Engineering Corporation (SWEC). The SWEC personnel were primarily
working on engineering projects concerning Unit 2 since much cf the work-
ing knowledge for this unit still rested with the contractor. However,
the SWEC organization was considered much the same as another section of
the licensee's engineering orcanization except that a licensee engineer
was assigned to monitor each project performed by SWEC. SWEC used the
same procedures as the licensee in controlling work performed.
The overall resources for engineering support greatly diminished during
the current assessment period as the licensea completed construction and
startup on Unit 2. Unit 2 completion led to a lange reduction in
resources (from 6000 to 2000 workers) with tha support responsibility
being assumed by the license 2 on-site enginee aing department as augmented
by SWiC. In recognition of the increased work load presented by two
operational units, the l'censee added twenty odditiona; Jositions in the
NED to staff for Unit 2 operations and ensure adequate support for both
unit .
Multiple or complex events appelred to challenge available
re~ rces, but in general, the existing manpower was sufficient to meet
demand.
Procedural control of work in the engineering department was good. Records
of implementation of engineering work including task specifications, pro-
curement controls, safety evaluations and project documentation were read-
ily available as part of the design control packages. The procedures were
adequate and, in a'l cases observed, were being implemented. The observa-
tions included both short and long term projects. Active projects were
discussed in daily meetings to assist in preventing problems. Plant staff
participated with engineering management in establishing project prior-
ities thus ensuring timely resolution of significant operational problems.
-- - - - . .. --
. . !
. 30
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The Engineering Department had a strong training program for maintaining
individual engineers' knowledge current. The Nuclear Engineering and ;
Records Unit maintains training records of engineering personnel, -
including required reading checklists, which require engineers to review
various engineering, administrative and . quality assurance procedures, .
Regulatory Guides and the relevant ' parts of the Code 'of Federal Regula- !
tions, Title 10. Supplemental Nuclear Engineering Department management,
technical and profe'.:,ional development training classes, seminars and l
lectures taken by the staff also were tracked on a computer data base _for
each employee. To ensure knowledge of changes to engineering procedures, .
'
the Nuclear Engineering Department routed a copy of the. procedure with an-
acknowledgement signature required to each section member for review of
the revision.
,
'
Technically sound support was provided to resolve, at least partially, the
long-standing problems with the Unit I fu.dwater control valves, rod con-
- trol cabir.ets, and vital bus No. 3 by hardware design modifications. Time-
ly support to operational events allowed Unit 2 to cornplete electrica!
modifications following the complex loss of off-site power event on
November 17, 1997 and start up five days later. Responsiveness was also
exhibited following the identification that certain required Unit I con-
trol room indicators had been inadvertently deleted in 1980, such that '
, proper indication capability was restored days after discovery. Just
after the close of the period, Unit 1 experienced a trip due to personnel
4
error. A second trip occurred duri g restart that required engineering
,
support and engineering perso.inel, ' uluding mechanical, electrical and -
I&C specialists, to be calleo in on : third shif t fu support. Overall,
support in response to events was very good and improvements in resolving
iong-standing problems were noted.
,
Engineering support was complete and adequate with respect to procurement
activities, potential inter-system LOCA (Event V) review, - reactor trip
breaker modifications, outage activities, and NUREG 0737 nost accident *
sampling systen issues. Further, the 'licensM developed n extensive
engineering program to address the equipment environmental qualificai;on *
l
requirements imposed sy 10 CFR 50.49. A Unit 2 team inspection . verified l
that a sound program had been developed and was being implerr.cnted to t
'
ensure that environmentally qualified equipment was being properly j
maintained. No significant concerns were identified during the inspection '
indicating that a comprehensive and technical!y thorough effort had been l
!- mounted. An extension of this program was the inspection effort to deal >
- with Limitorque valve actuator problems. The program wao found to' be l
thorough and in depth; however, an inspection of Unit 1 immediately
following the assessment period identified problems in the use of
,
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unqualified wirenuts and unqualified wire in limitorque operators which '
maj raise significant concerns with ti.e EQ program.
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The technical content of the licensee's emergency operating procedures was
adequate; however, a number of deficiencies and inconsistencies were iden-
tified, particularly in the Unit 1 procedures. These deficiencies indi-
cated a weakness in site management's attention to detail in validation,
verification and 1:4 mentation of high quality emergency operating pro-
cedures. Procedural i.sman factor deficiencies were compensated by opera-
tor experierce; operator performance during plant events was excellent,
in summary, improvements were noted in engineering support for long term
problems and plant events. Tr ese improvements were achieved during a time
of transition with good evidence that licensee senior management was in-
volved in matching staffing to site needs. Continued senior management
attention is needed to assure that engineering / support resources are ade-
quate for the increased demands inherent in two unit operation, especially
in support of the back-to-back refueling outages planned in the next
period.
2. Conclusion:
Category 2
3. Board Recommendations:
Licensee: Implement a program to resolve the deficiencies existing in the
Emergency Operating Procedures in a timely manner.
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. 32
.
H, Safety Assessment / Quality Verification (729 hours0.00844 days <br />0.203 hours <br />0.00121 weeks <br />2.773845e-4 months <br />, 7'4)
1. Analysis
Management involvement in assuring quality has been considered as a
separate functional area in past SALPs in addition to being one of the
evaluation criteria in each functional area.
This area has been expanded to encompass activities previously evaluated
' in Licensing, including safety evaluations. This discussion is a synopsis
of quality and safety evaluation ph!1osophies reflected in other func-
tional a eas. In assessing this area, the SALP -Board has considered at-
tributes which are key contributors in assuring safety and verifying qual-
ity. Implementation of management goals, planning 'of routine activities,
worker attitude, management involvement, and training are examples. This
area received a Category 2 rating for both Unit 1 and Unit 2 in the last
assessment period. Strengths were identified in worker attitude, first
line supervision, QC aggressiveness and management involvement. A weak-
ness was identified in the overemphasis by QA on documentation complete-
-
ness rather than on assessment of the technical adequacy of the area
audited.
Significant resources continued to be dedicated to the assurance of
quality. The recent licensee commitment to procuring a new simulator for i
Unit 2 represents a significant capital investment in enbincing the '
quality of Unit 2 operator training. Manpower and analysis resources were
also allocated :to the licensee's recently completed Safety System
Functional Evaluation (SSFE) of the Unit 1 AN system. The SSFE was a
.
'
broad-based technical audit involving over 3000 man hours of effort and
was modeled after the NRC Safety System Functional Inspection. The SSFE
-
was used to reconstitute the design bases of the much-modified Unit 1- AFW l
system and reconcile differences between the two units as well as provide
enhanced assurance of AN operability. The licensee - plans to conduct
SSFEs on c' qer Unit 1 safety systems af ter reviewing the results of the
4
AFW SSFE.
In the licensing area, the licensee demonstrated a good working knowledge
of applicable regulations, guides, standards and generic issues during the
period, in particular, during the final licensing stages for Unit 2.
.
The I
lv.ensee was generally responsive in addressing unresolved issues; this
was especially notable during the completion of the Unit 2 Technical
Specifications. Licensee preparedness, technical competence and effec-
tively proposed resolutions were evidence of the licensee's commitment to
resolve safety issues in a timely manner. Over 100 licensing actions were
completed incleding application of leak-before-break technolor Onit 1).
l
ATWS rule implementation (Unit 1 and 2), and inservice tes of pumps
ard valves (Unit 2). Co.. ervatism was consistently exhibitt .. .th sound
, technical judgement provided for most deviations from NRC guidance.
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Prior to receipt of the Unit 2 full power license, the licensee conducted
a self-assessment of startup testing and power operations at the 50% power
testing plateau. Good agreement was noted between the licensee's self-
assessment and the independent assessment made by the NRC - staf f. - The
licensee's self-assessment was noted to be strong on root cause analysis,
to be self-critical where warranted, and to use existing management in br--
mation systems; The use of already in place resources instead of a-unique
task force approach was a' notable strength since it_ indicated that the
analysis tools are consistently available to licensee managemert. .This
self-assessent and the ongoing use by senior management of the contribu-
ting reports and trending / tracking documents were positive initiatives.
Utilizing the evaluation methodology presented ta NUREG-1022, Licensee
Event Report System, the overall quality of LERs exhibited weakness in
that they contained inaccuracies .and overall weaknesses in ' report com-
pleteness, root' cause determinations and safety ' significance evaluations.
.The licensee was responsive to these concerns as ' demonstrated by the
significant improvements in LER quality noted during the last quarter of-
this assessment.
A formal and systematic approach to root cause analysis was implemented
later in the assessment period which forced a broad-based approach to
event review and which led to higher quality analysis. The ISEG developed
a computer program which compares Unit 2 trip response to a standard trip
withou other failures. The program flags which -of over 100 computer
address data points do not appear within the expected time "window" and
will greatly facilitate the identification of equipment failures or
unexpected component' response following an event. The program also
establishes a database which can be analyzed for trending studies. This
program is a notable initiative which, when fully implemented and extended
to Unit 1, will enhance the licensee's ability to assess plant response to
events.
Management oversight has generally been etfective, considering the in-
creased demands the Unit 2 project placed on licensee resources. Senior
management was involved in improving availability of safety related com-
ponents and systems, promoted accountability and ownership among licensee
staff, ensured participation in INPO audits to learn from other utilities :
and kept abreast of regulatory and industry initiatives to be aware of '
potential problems. Especially effective oversight was denonstrated at
Unit 2 during MSIV replacement, recirculation spray heat exchanger flush- '
ing and startup testing. Actions taken by management have achieved i
partial resolution of two long standing equipment problems at . Uni t 1; l
Vital Bus No. 3 inverter unreliability and FCV vibration-induced failures. i
Vital Bus No. 3 inverter trips have continued to occur, but an automatic
bypass circuit was installed which provides a backup power supply and has
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_ _ _ . . _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ _ _ . _ _ _ . _ _ . _ _ . _ _ _ _ _ . _ . . . _ _ _
- . - - .. -
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prevented the inverter failures from causing plant trips. Additional B0P
'
modifications have greatly reduced FCV. vibration during power operation, i
although the greater feed flow available post-modification has appeared to ,
i increase the severity of the transient following a plant trip during
startup. After the close of the assessment period, .other Unit I feed- ,
water, SG level control and RCS pressure problems indicate revised flow ,
characteristics for the FV systems which may r.ot have been fully antici- '
pated by the licensee. Additional attention appears to be required to ;
j fully resolve.the problems with the inverter and FCVs. ;
.
~
The various station ' safety committees functioned well during the period.
i The Offsite Review Committee (ORC) included rnembers of senior corporate !
personnel and continued to be an effective and aggressive organization' .
One example of the ORC's use as. a management tool was the allocation of
resources to conduct Safety System Functional Evaluations (SSFEs) to
assure safety ' system reliability and upgrade design basis documentation. ..!
The continued onsite location of senior corporate personnel and engineer- l
ing support groups enhanced the oversight and integration functions essen-
.tial to the solution of complex problems. The _0RC, acting through sub- l
committees, acted to improve EDG reliability by installing air dryers in
the starting air system, to improve fire damper reliability by implemen- L
ting a specific maintenance program and to reduce unp'aned reactor trips
by installing an inverter auto bypass circuit to preve.:t recurring inver-
ter trips from causing reactor trips.
,
A major licensee reorganization was announced-late in the assessment per-
4
tod following Unit 2 commercial operation. The new senior onsite execu-
i tive, Vice-President Nuclear, began to restructure his staff to integrate J
l the Unit 2 project personnel into the site organization. The large QC ,
staff, whose thoroughners and aggressiveness was a notable strength during
Unit 2 construction, was greatly reduced as the work for the group was i
completed. The QA organization, previously noted to overemphasize [
"paper", has been tasked with increasing technical assessment and quality !
enhancement. Audit results showed some improvements in quality and tech- f
nical depth near the end of the assessment period.but further improvements l
appear to be warranted. '
In summary, during this assessment period, very effective management was r
j evident in achieving the licensing, testing and commercial operation of j
j Unit 2. Partial resolution of longstanding Unit 1 problems was also
,
achieved. Some areas were identified which need further management atten-
l tion, but notable initiatives such as the Unit 2 simulator commitment, the ;
Unit 2 self-assessment, the Unit 1 SSFE program and programmatic root
cause analysis improvements indicate a strong and long term management
dedication to assuring quality.
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2. Conclusion:
Category 2
3. Goard Recommendations:
None
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_. _. ._ _
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.
I. Preoperational and Startup Testing - Unit 2 (2182 hours0.0253 days <br />0.606 hours <br />0.00361 weeks <br />8.30251e-4 months <br />, 21%)
,
1. Analysis ':
During the previous assessment period, Preoperational Testing was assigned I
a Category I rating. The preoperational test program was identified as a
notable strength, with well controlled tests and highly professional
problem solving. The licensee successfully completed several major
testing milestones- on or ahead of schedule. Test data were of high ,
4 quality with a conservative threshold for identifying potential !
, deficiencies. Test results were _ reviewed in a thorough, well organized
manner.
.
During this period, the licensee continued to demonstrate a high level of
performance while completing the preoperational test program. Strong
management oversight occurred at the twice daily planning meetings, test ;
1 results review Lwas very good and test deficiency resolution was
! technically sound.
Good test personnel performance occurred durir.g the preoperational loss of
offsite power test, containment leak rate tests, retests of the reactor .
j head vent system, ECCS flow and pressure drop te sting, and testing for '
minimum continuous spray flow. In many of the large integrated tests, :
only minor test deficiencies were recorded indicating good planning. Test !
reports were well organized and complete. Justifications for all test :
completion deferrals (beyond core load) were valid. Most of the new start
up schedule dates assigned for test deficiency completion ware realistic '
and consistent with the work to be performed. The licensee's letter '
requesting deferral of - some operational tests was well thought out and
technically sound. i
,
Personnel with experience gained from the preoperational test program were
!
used in the development of the startup test program. Some problems oc- t
curred during the transition phase in that the initial procedures still !
reflected many of the controls, such as constructicn deficiencies, which ;
were not con si ster.t with the controls that would be required by an '
operating license. The licensee's performance in the preparation of the i
- startup testing improved during the course of the program. Management was .
'
,
fully involved in the preparation and review of the procedures with
completed procedures being approved by the Joint Test Group (JTG) and the :
On Site Review Committee prior to being issued. Plc.nt manage.?ent tracked '
test procedure development status and test schedule, and were knowledge-
] able of the technical details,of test content.
s
Licensee performance throughout the entire fuel loading periou was good,
with activities being performed in a deliberate, and carefully controlled {
manner. Fuel loading activities were conducted by qualified personnel and '
interfaces among various groups were smooth, problems . identified were
- properly evaluated and resolved witn management involvement and control
a evident. Licensee performance during this evolution was enhanced by '
l utilizing persennel experienced in loading fuel at Unit 1. !
'
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. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ . _ _ _ _ . _ . _ _ _ _
.' .
. 37
Licensee performance during startup testing was also good. Management
oversight and control of testing activities were observed to be good and
effective with consistent monitoring of plant activities during najor
plant evaluations and tests. Strong management attention to the safety
implications of problems identified by startup testing was evident.
Information and work status were presented clearly and objectively at the
daily plant meetings. Management presence at these meetings helped in
resolving schedule conflicts and assigning priorities among many
activities.
Equipment problems identified during startup testing were properly
evaluated and followed. Management attention to these problems was
consistently evident and factored into later testing. For example, a
problem with the reactor coolant pump underfrec,uency relays was identi-
fied, but not fully rerolved for several days. In the interim period,
further testing was conducted using offsite power supplies so the problem
with the fast transfer capabilities of these relays would not be a factor.
Other instances of problems were identified in configuration control,
information feeduack and pretest briefing, but licensee corrective action
was effective in preventing repetition and these examples are considered
isolated cases.
The startup test administration program was logical and comprehensive. A
change in the test plan was made toward the end of the 30'. power plateau
to defer the MSIV closu e test and the loss of offsite power test until
after the 50*. power non-transient type tests. The change was propurly
reviewed by the appropriate licensee groups and NRC concurrence was
obtained in a timely manner. This schedule change allowed the thorough
exercise of- BOP equipment prior to the plant challenging tests at 30%
power. If a post-trip outage had been nece s sa ry, then any problems
identified in BOP equipment could also have been ad ressed. In another
case, the licensee was able to avoid an additional plant challenging trip
test from 100*. power. The licensee elect)d to wait until an operational
event resulted in a trip from full power. Until such time, recorders
remained hooked up to record the necessary data and the plant was uperated 1
with conservatively reduced trip setpoints (Over Pressure Delta T and Over
Temperature Delta T). These e. aamples demonstrated the strong, l
proactive involvement of licensee senior management.
1
Particularly effective interfaces were developed between the Operations '
and Test Groups. Prior to performing testing, pretest briefings were I
conducted by test personnel. Also before transiert type tests, the
Nuclear Shift Supervisor reminded the operation crews to monitor key !
parameters during the test. Test prerequisites, initial test conditions
!
and plant responses were jointly monitored by operations and test
personnel, fest identified problems were correctly and promptly fed back
to Operations and corrective actions were properly taken.
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The effective interf ace between the Nuclear Shif t Supervisor (NSS) and l
test supervision was a notable strength. Prior to the MSIV closure test,
the NSS discussed that he would wish to reopen the MSIVs as soon as
feasible to restore the normal path of decay heat removal. The reactor
tripped within ten seconds of MSIV closure; the NSS oversaw the accurate
completion of immediate actions, asked the test supervisor about the
MSIVs, and was able to quickly reopen them such that no steam generator
relief valves were actuated. Excellent control of the loss of offsite
power (LOOP) test was also demonstrated. After the plant was stabilized,
the NSS asked the test supervisor about reopening the MSIVs. In this
case, the test supervisor requeshd 30 minutes of data under the existing
conditions to assure all data trends were captured. This request was
accommodated by the Operations crew and the desired data was acquired.
These examples were indicative of the excellent control and cognizance of
plant activities that the on-shift operations staff exhibited throughout
this period of numerous parallel on going activities.
The NRC reviewed Unit 2 startup experience with emphasis on unplanned
reactor trips and ESF functions during startup testing through commercial
operation. Unit 2 had about an average number of unplanned trips and
fewer than average ESF actuation, TS violations and LSSFs corapared with
similar facilities, as documented in NUREG-1275, "Operating Experience
Feedback Report - New Plants" July 1987. Unit 2 completed the startup
testing program in three months af ter initial criticality compared with
the greater than ten-month average for NUREG-1275 units. The Unit 2
performance was comparable in scrams and substantially better than average
in the startup testing program taken as a whole, and demonstrated a very
good level of performance during that active period. The success of the
startup program was also demonstrated by the high level of operational
performance of Unit 2 during the first 100 days of commercial operation
with a scram rate less than half the NUREG-1275 average, ESF rate less
than one-fourth the average, and no TS violations or LSSFs. Effective
senior management oversight, active day-to-day management involvement, and
strong technical troubleshooting during the startup testing program were
key factors in attaining a high level of performance.
In summary, the licensee demonstrated a high level of performance in the j
area of Preoperational and Startup Testing. A slow and deliberate ;
approach to initial criticality was observed and initial low power physics l
testing was conducted in an almost error-free manner. A strong and
effective interface was maintained between the licensed operators and the
test crew. Both groups showed flexibility in cooperating with each other i
to acquire good test data while enhancing plant safety. First hand {
obse vations of control room performance following trips from power showed i
excellent operator initial response and subsequent licensee problem '
solving efforts.
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. 39
2. Conclusion:
_
Category 1
3. Board Recommendations:
None
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J. Training programs
1. , Analysis
A similar area, Training and Qualification Effectiveness, was assessed as
Category 2 for Unit 1 last period. Training was considered as part of
Operational Readiness for Unit 2 which was assessed as Category 2. Ample
resources were observed to be devoted to training and effectiveness was
noted to be good as evidenced by low incidence of personnel error. The
performance of license candidates on Unit 1 during the last period was
relatively noor declining from the previous assessment period as 9 of 16
SR0 and 5 of 17 R0 candidates failed various portions of NRC administered
exams. Weakened program effectiveness was considered to be indicative of
decreased management oversight. The high success rate of license candi-
dates on Unit 2 with 16 of 19 passing NRC administered e.v.aras is in part
due to significant prior operating experience.
During tnis assessment period, the performance of license candidates de-
clined at both units as 5 of 6 SRO and 4 of 6 R0 candidates failed various
portions of NRC administered exams for Unit 1, and 5 of 19 SRO and 4 of 11 ,
R0 candidates failed various portions for Unit 2. The Unit 1 failures all
involved requalification exams and led to the NRC evaluation that the
requalification program was unsatisfactory. The linit 2 decline in candi-
date performance was also substantial but was due, in part, to the un-
usually high level of previous licensed experience of the initial group of
candidates with the recent performance approximating the industry average.
The knowledge and use of normal and abnormal procedures was a generic
weakness affecting canaidates cf both units. Additionally, numerous human
factors deficiencies were identified in the Unit 1 emergency operating
procedures as was a lack of quality assurance review. The decline in per-
formance was indicative of poor management oversight of the training pro-
gram and preoccupation with other issues such as dual licensing of opera-
tors and Unit I simulator adequacy for Unit 2. Evidence of increased
senior management involvement was noted late in the period with the
commitment to provide a new simulator specific to Unit 2 which should
significantly enhance the quality of training available to Unit 2
operators. Similarly, the licensee is implementing commitments to revise
the requalification program including learning objectives, lesson plans
and examination development.
Training for maintenance personnel, emergency preparedness personnel, the I
security force, and engineers was good. Training in the area of radiation
protection was also good but there is a need for additional emphasis on
.
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.
, 41
In summary, the significant weaknesses in the licensed operator training
program noted during the period overshadowed the pnerally sound perform-
ance of other training activities and indicated a need for more senior
management attention. These weaknesses, when viewed with weaknesses in
knowledge and use of E0Ps during examinations as well as the E0P proced-
ural deficiencies and inconsistencies as discussed in the Engineering /
Technical Support functional area, raise a concern regarding the support
provided the operators to enable them to handle significant or unusual
transients or events.
'2. Conclusion:
l
1
Category 3, Improving, i
3. Board Recommendations
Licensee:
Increase senior management attention to licensed operator training with
particular emphasis on the,requalification program.
E:
None
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V. SUPPORTING DATA AND SUMMARIES
A. Enforcement Activity
No of Violations in Each Severity Level
Functional Area V IV III II I Total '
i
Unit 1
Plant Operations 3 3
Radiological Controls 2 2
Maintenance 2 2
Surveillance 1 1
Security 0
Engineering / Technical Support 1 1
Safety Assessment / Quality 0
Verification
l Unit 1 8 1 9
l Unit 2
Plant Operations 0
Radiological Controls O
Maintenance O
Surveillance O
Security 0
Engineering / Technical Support 3 3
Safety Assessment / Quality
Verification 1 1
Unit 2 Total 1 3 4
Two enforcement conferences were held with the licensee at the NRC Region
! Offices. On July 2,1937, an entorcement conference was held regarding
the inoperability of the Unit . chlorine detection system. The
March 24, 1988, enforcement conference was in regard to defeated
containment high-high pressure bistables at Unit 1. No civil pen 11 ties .
resulted from the associated violation s l
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B. Inspection Hour Summary
Annualized
Actual _ Hours Percent
Plant Operations 3388 2756 32
Radiological Controls 874 711 8
Maintenance 742 603 7
Surveillance 790 643 7
Emergency Preparedness 447 363 4
Security 433 352 4
Engineering / Technical
Support 1065 866 10 ,
Safety Assessment / Quality
Verification 729 577 7
,
Preoperational & Startup
Testing _2182 1775 _21
10650 6646 100
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C. Licensee Event Report Causal Analysis
Number By Cause Code
Functional Area A B C D E X Total
Unit 1
Plant 0parations 2 2 2 6
Maintenance 1 3 4
Surveillance 2 8 1 11
Engineering / Technical Suppert 1 2* 3
Unit 1 Total 5 3 0 8 7 1 14
- LER 87-13 contained two related reportable events.
Number By Cause Code
Functional Area A B C D E X Total
Unit 2
Plant Operations 1 3 2 1 1 8
Maintenance 4* 1 5
Surveillance 6 1 7
Engineering / Technical Support 2 1 3
Preoperational and Startup
Testing 5 4 3 3' 2 17
Other 1 3 4
Unit 2 Total 17 9 2 6 8 2 44
- LER 87-12 contained two related reportable events.
Cause Codes:
Combined Total y
A Personnel Error 22 32
B Design, Manufacturing, Construction
or Installation Error 12 18
C External Cause 2 3
0 Defective Procedures 14 21
E Component Failure 15 22
X Other 3 4
The following common mode events were identified:
Approximately one-third of the events are attributable to personnel error;
surveillance activities accounted for the greatest fraction (36*.) of these
events.
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a 45
Licensee Event Report Causal Analysis (Continued)
While 12 events were attributed to design, manufacturizing, construction
c,r installation errors, most were identified during pre operational and
start-up test of Ur? 2 as would be anticipated.
Inadequate procedures accounted for A events of which 9 were related to
the surveillance program,
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