ML20126C839
| ML20126C839 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 05/13/1985 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20126C612 | List: |
| References | |
| 50-277-85-99, 50-278-85-99, NUDOCS 8506140541 | |
| Download: ML20126C839 (58) | |
See also: IR 05000277/1985099
Text
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
Philadelphia Electric Company
PEACH BOTTOM ATOMIC POWER STATION
May 13, 1985
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TABLE OF CONTENTS
Page
I. INTRODUCTION...............................................
1.1 Purpose and 0verview.................................. I
1.2 SALP Board and Attendees.............................. 1
4 1.3 Background............................................ 1
II. CRITERIA................................................... 8
III. SUMMARY OF RESULTS......................................... 10
IV. PERFORMANCE ANALYSIS....................................... 13
4.1 Plant Operations...................................... 13
4.2 Radiological Controls................................. 17
4.3 Maintenance........................................... 21
4.4 Surveillance.......................................... 24
4.5 Fire Protection / Housekeeping ...... .................. 26
4.6 Emergency Preparedness................................ 28
4.7 Security and Safeguards............................... 30
4.8 Refueling / Outage Activities........................... 32
4.9 Licensing Activities.................................. 35
V. _ SUPPORTING DATA AND SUMMARIES.............................. 37
5.1 Investigations and Allegations Review................. 37
5.2 Escalated Enforcement Action.......................... 37-
5.3 Management Conferences................................ 38
5.4 Li cen s ee Eve n t Repo rt s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.5 Forced Outages and Unplanned Scrams. ................ 39
TABLES
Table 1 Licensee Event Reports T1-1
Table 2 Violations T2-1
Table 3 Inspection Report Activities T3-1
Table 4 Inspection Hours Summary T4-1
Table 5 Forced Outages and Unplanned Scrams T5-1
Table 6 NRR Supporting Data and Summary T6-1
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.I. INTRODUCTION
1.1 Purpose and Overview
The Systematic Assessment of Licensee Performance (SALP) is an inte-
grated NRC staff effort to collect the available observations and
data on a periodic basis and to evaluate licensee performance based
upon this information. SALP is supplemental to normal regulatory
processes used to ensure compliance to NRC rules and regulations.
.SALP is intended to be sufficiently diagnostic to provide a rational
basis for allocating NRC resources and to provide meaningful
guidance to the licensee's management to promote quality and safety
of plant construction and operation.
An NRC SALP Board, composed of the statf members listed below, met
on May 13, 1985, to review the collection of performance
observations and data and to assess the licensee performance in
accordance with the guidance in NRC Manual Chapter 0516, " Systematic
Assessment of Licensee Performance." A summary of the guidance and
evaluation criteria is provided in Section II of this report.
This report is the SALP Board's assessment of the licensee's per-
formance at the Peach Bottom Atomic Power Station for the period
January 1, 1984 through March 31, 1985.
1.2 SALP Board:
R. W. Starostecki, Director, Division of Reactor Projects (DRP)
W. F. Kane, Deputy Director, Division of Reactor Project < (DRP)
T. T. Martin, Director, Division of Radiation Safety and Safeguards
(DRSS)
S. D. Ebneter, Director, Division of Reactor Safety (DRS)
S. J. Collins, Chief, Projects Branch No. 2, DRP
R. M. Gallo, Chief, Reactor Projects Section 2A, DRP
J. F. Stolz, Chief, Operating Reactors Branch 4, NRR
G. Gears, Licensing Project Manager, NRR
T. P. Johnson, Senior Resident Inspector, Peach Bottom Atomic Power
Station, Units 2 and 3
Other NRC Attendees:
J. E. Beall,-Project Engineer, RPS 2A, DRP
J. H. Williams, Resident Inspector, Peach Bottom Atomic Power
Station, Units 2 and 3
1.3 Backaround
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. Peach Bottom Units 2 and 3 were issued operating licenses on
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October 25,1973 (DPR-44) and July 2,1974 (DPR-56), respectively.
Unit 2 began commercial operation during July, 1974, and Unit 3
began commercial operation during December, 1974.
Presently, Unit 2 is recovering from its sixth refueling / outage and
Unit 3 is in power coast down from its sixth cycle. Major items of
interest which occurred during the assessment period are depicted
below.
(1) Licensee Activities
Unit 2
The unit operated at or near full power from January 1 through
January 28, 1984. On January 28, 1984, a controlled shutdown
was initiated to repair a leak on the RCIC testable check valve.
The unit returned to power on February 2, 1984, and on February
18, 1984, the unit was removed from service for Main Steam
Isolation Valve (MSIV) and Feedwater Check Valve leak testing.
During this outage, an inspection of the' Torus Vent Header was
conducted in response to generic BWR concerns. An isolated
defect in the workmanship, associated with previous torus modifi-
cations, was identified and repaired. The unit returned to
service on February 25, 1984.
Power reductions occurred on February 27, 1984, and again on
March 2,1984, for control rod pattern adjustments and r
condenser water box inspection and repair. At 2:19 a.m., on
April 28, 1984, the unit was shutdown for refueling and
a recirculation and RHR pipe replacement outage.
During May,1984, the vessel head, steam dryer, and moisture
separator were removed and all fuel was transferred from the
reactor core to the spent fuel pool in preparation for pipe
replacements. The new piping material is type 316 austenitic
stainless steel (controlled chemistry) and is less susceptible
to intergranular stress corrosion cracking.
In June, 1984, the core spray sparger inspection, repair of
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fuel pool gate cracks, Source Range Monitor and Intermediate
Range Monitor instrument dry tube inspections, installation and
testing of the jet pump diffuser plugs and installation of.
vessel annulus shielding in front of the suction nozzles of the
recirculation loops were completed.
Installation of recirculation discharge nozzle caps was com-
pleted, measurements for head spray piping replacement were
taken, all recirculation suction nozzles were cut, and pre-
operational tests for chemical decontamination of the pipe to be
removed were completed during July,1984.
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During August, 1984, after completion of the cutting and
capping of the recirculation and RHR piping, the reactor vessel
was flooded to the head flange and chemical decontamination of
the piping started. The jet pump plugs were removed and jet
beams were replaced. The recirculation and RHR piping was
drained following completion of chemical decontamination, and
the jet pump plugs were replaced and the vessel was flooded.
In September, 1984, control blade relocation and replace-
ment, removal of the jet pump nozzle plugs, and radiography on
the recirculation N-2 (safe end) nozzles were completed. The
"A" and "B" recirculation suction and discharge valves were
3_ disassembled and removed from the drywell, and temporary reactor
water cleanup pumps were installed in the reactor-vessel.
During October,1984, replacement of the nuclear instrument dry
tubes in the reactor, head spray piping installation, and
removal of the recirculation and Residual Heat Removal piping
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were completed. The "B" recirculation pump motor was removed
from the drywell.
Both recirculation pump motors were uncoupled and removed from
the drywell during November, 1984. Decontamination and inspec-
tion of both recirculation pump shafts and impellers, fitting of
both the "A" and "B" recirculation loop ring headers, decontamin-
. ation of the "A" and "B" loop recirculation, loop. valve bodies
and pump bowls, removal of the recirculation pump flow splitters,
replacement of two recirculation inlet safe ends, removal of two
additional recirculation inlet safe ends, ard replacement of the
3A feedwater heater were completed.
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In December,1984, January and February 1985, the major activity,
was pipe replacement and welding operations. Also, both "A" and
"B" recirculation pump motors were returned to the drywell.
Ddring March,1985, all small bore pipe welds needed to support
vessel fill were complete. The "A" and "B" recirculation pump
seals were installed; the main steam drain valves were
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replaced; the four recirculation motor operated valves were
reassembled; and the Residual Heat Removal valve which leaked
during the primary recirculation pipe flush was repaired.
Unit 2 remained shut down for the refueling / pipe replacement
outage at the end of the assessment period. Current plans
project startup during June,1985. In addition to replacing all
the reactor recirculation piping, RHR (drywell portions), piping
head spray and reactor water cleanup (drywell portions) piping,
the ten recirculation inlet safe-ends and two jet pump penetra-
tion seals, a number of major modifications were performed.
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Unit 3
The unit began the assessment period at full power. On
' January 14, 1984, the unit was removed from service due to
flooding of the condensate pump pit which was caused by an
open vent valve on a main condenser water box. The flooding
of the condensate pump room resulted in damage to the
condensate pump thrust bearings. During the manual scram on
January 14, 1984, control rod (34-27) failed to insert within
the prescribed time due to sticking of a scram pilot solenoid
valve. The unit was returned to power on January 27, 1984.
On February 9,1984, the unit shutdown on an automatic scram
high neutron flux signal. The scram occurred following a
trip of the "B" reactor feedwater pump due to high vibration.
Loss of the feedpump initiated runback of recirculation pumps
and main turbine. Turbine runback did not automatically
terminate as designed, resulting in a reactor pressure
transient that caused the high flux spike. Following repairs,
the unit returned to service on February 10, 1984.
During March and April, 1984, load was reduced several times
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for inspection and tube plugging of the main condenser waterbox
along with control rod pattern adjustments.
The unit was removed from service for a feedwater heater repair
on June 2, 1984. The RCIC steam supply isolation valve was also
repaired and tested during this outage. Since cracking had been
found on the Unit 2 jet pump instrumentation nozzles, the Unit 3
nozzles were also checked during this outage and indications
were found on both the A and B instrumentation nozzles. Weld
overlay repairs were performed on both welds.
On July 11, 1984, the unit tripped when a lightning strike near
the substation initiated a sequence of electrical breaker
openings culminating in an automatic reactor scram. While the
unit was shut down, a reactor water cleanup system isolation
valve failed to open during a functional test. The valve
operator was replaced to correct the problem. Also, an
external leak on the condensate-system drain cooler was
repaired. The unit returned to service on July 15, 1984.
Unit 3 automatically scrammed due to a feedwater controller
failure which resulted in a low reactor water level on August
21, 1984. Reactor startup commenced following completion of the
work required to return an emergency diesel generator to service.
The diesel generator had been out-of-service for a scheduled
annual inspection. Unit startup was initiated August 24, 1984.
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-Load was reduced on September 29, 1984 for control rod
pattern adjustment, condenser circulation pump repair, and
condensate pump work.
On October 25, 1984, load was reduced to 80% power to reduce
the high off gas radiation levels of approximately 45,000
uCi/second and mitigate. future fuel failures. After the
power reduction, the off gas radiation level was 24,000
uCi/second with the unit at 80% power.
The unit was shut down to repair the Traversing Incore Probe
(TIP) machine and correct a 4 gpm unidentified leak inside the
drywell on November 6,1984. The unit returned to service on
November 12, 1984. On November 14, the "B" recirculation pump
tripped when water, leaking into a pressure switch, shorted its
contact thus energizing the trip circuit of the pump motor.
During the. restart of the pump, the reactor scrammed on an
Average P4er Range Monitor (APRM) high flux signal caused by a
small scram margin. The unit was returned to service on
November 16, 1984. On November 24, 1984, load was reduced to
.repairicondenser water box leaks.
The dnit reduced power on December 1, 1984, to 65% power to
repair condenser waterbox leaks. On December 10, 1984, the
unit was removed from service for repair of offgas recombiner
condenser tubes. While in~ hot standby, the "B" recirculation
pump tripped on motor overcurrent. This was caused by the
motor generator set hydraulic coupling experiencing a scoop
tube linkage failure. Following repairs to the recombiner
condenser and the recirculation motor generator set scoop
tube positioner, and checkout of the MG set, pump motor and
associated controls, the unit was returned to power. Load was
reduced on December 15, 1984, for a control rod pattern
. adjustment. A special hydrogen water chemistry test was
performed on December 17-20, 1984. The purpose of the test was
to obtain data to evaluate the results of injecting hydrogen
into the feedwater to reduce the oxygen concentration in the
primary coolant as a pipe crack mitigation measure. The unit
was operated at 90 to 100% power during the test. Load was
reduced on December 20, 1984 to 85% power due to offgas
radiation levels.
On January 5,1985, load was reduced to 66% power to repair
a broken test tap on the 3A condensate pump. The unit
returned to 80% power on January 6, 1984. On January 7,1984,
the "A" loop torus cooling valve would not stroke and was
declared inoperable. An Unusual Event was declared and
shutdown was initiated on January 15, 1985, when the E-4
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diesel generator and the "A" loop torus cooling valve were
declared inoperable. The valve was returned to service by
the time the unit reached 25%. The E-4 diesel generator was
returned to service on January 21, 1985.
The unit was shut down on January 23, 1985, to clean the
main generator exciter brushes. (An oil leak was causing a
ground fault alarm.) On January 24, 1985, the unit returned to
service and reached 90% power the next day.
The unit was taken out of service to perform required surveil-
lance tests on February 1, 1985. Three of the eight Main Steam
Isolation Valves (MSIV's) tested failed local; leak rate testing
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and required repair prior to restart. Startup was begun on
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February 25, 1985. The unit was returned to service following
repair to the 71L relief valve bellows and replacement'of a
solenoid valve which prevented closure of a reactor head vent
valve (AO-17). Following repair of a drywell airlock door seal,
the unit was returned to service on March 1, 1985.
Later on March 1, a scram was caused by condenser low vacuum
resulting from a missing plug in a relief valve on the 2A fned-
water heater. A metal plug was installed, several minor vacuum
leaks were repaired and the unit was returned to service that
same day. On March 9, 1985, load was reduced to 55% power.for
43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> to accommodate control rod pattern adjtttment and
helium leak testing of condenser waterboxes. Two small leaks
were located and repaired. Unit operation (during power coast
down prior to refueling) was limited to 90% power throughout the
remainder of the assessment period due to high offgas activity.
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(2) Inspection Activities
~Two NRC resident inspectors were assigned to the site during the
assessment period. The total NRC inspection hours for the assessment
period was 5422 hours0.0628 days <br />1.506 hours <br />0.00896 weeks <br />0.00206 months <br /> (resident and region-based) for the 15 month
assessment period. The total inspection hours when normalized to a
12 month (1 year) period are equivalent to 4338 hours0.0502 days <br />1.205 hours <br />0.00717 weeks <br />0.00165 months <br />. Distribution
of these hours for each functional area is depicted in Table 4.
Details of inspection report activities is presented in Table 3.
Emergency plan team inspections were conducted on October 16-18,
1984 (annual emergency exercise) and on January 8-11, 1985.
An Operations Assessment Team Inspection to assess the Unit 2 pipe
replacement outage was performed on July 16-20 and 23-27, 1984.
Special inspections were conducted as follows:
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To review individual rod scramming on January 5-20, 1984.
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To review security and safeguards on June 25-July 1,1984.
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To review inoperability of one diesel generator and one loop
of containment cooling on January 15-18, 1985.
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To review the contamination of several radiation workers on
February 13-15, 1985.
The NRC Region I NDE Mobile Van was onsite for an inspection
associated with Unit 2 pipe replacement on January 14-25, 1985.
The NRC Region I Mobile Radiological Measurements Laboratory was
onsite for an inspection on January 28 thru February 1, 1985.
Major enforcement issues occurring during the assessment period are
discussed.in report Section 5.2. Table 2 lists specific enforcement
data.
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II. CRITERIA
The following criteria were used where arpropriate in evaluating each
functional area:
1. Management involvement in assuring quality.
2. Approach to resolution of technical issues from a safety standpoint.
3. Responsiveness to NRC initiatives.
4. --Enforcement history.
5. Reporting and analysis of Licensee Event Reports, 50.55(e) reports
and Part 21 items.
6. Staffing (including management).
7. Training effectiveness and qualification.
To provide a consistent evaluation of licensee performance, attributes
associated with each criterion and describing the characteristics
applicable to Category -1, 2 and 3 performance were applied as
described in NRC Manual Chapter 0516, Part II and. Table 1.
The SALP Board conclusions were categorized as follows:
Category 1: Reduced NRC attention may be appropriate. Licensee
management attention and involvement are aggressive and oriented
toward nuclear safety; licensee resources are ample and effectively
used such that a high level of performance with respect to operational
safety or construction is being achieved.
Category 2: NRC attention should be maintained at normal levels.
Licensee management attention and involvement are evident and are
concerned with nuclear safety; licensee resources are adequate and are
reasonably effective such that satisfactory performance with respect to
operational safety or construction is being achieved.
Category 3: Both NRC and licensee attention should be increased. Licen-
see management attention or involvement is acceptable and considers nuc-
lear safety, but weaknesses are evident; licensee resources appeared
strained or not effectively used such that minimally satisfactory per-
formance with respect to operational safety or construction is being
achieved.
The SALP Board has also categorized the performance trend over the last
quarter of the SALP assessment period. The categorization describes
the general or prevailing tendency (the performance gradient) during the
.last quarter (January 1,1985 to March 31,1985) of the SALP period. The
performance trends are defined as follows:
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Improving: Licensee performance has generally improved over the
last quarter of the SALP assessment period.
Consistent: Licensee performance has remained essentially constant over
the last quarter of the SALP assessment period.
Declining: Licensee performance has generally declined over the
last quarter of the SALP assessment period.
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III. SUMMARY OF RESULTS
A. Overall Facility Evaluation
During this assessment period, Peach Bottom has demonstrated that they
have a staff and managers who are technically knowedgeable and are
involved in station activities affecting safety. The conduct of
plant operations, maintenance activities and surveillance testing is
sound and conservative. Licensee performance and response to NRC
licensing issues and actions was generally timely and technically
sound. Major weaknesses were identified in the functional areas of
radiological controls and security / safeguards. The summary ratings
of overall facility performance for each functional area, both during
the current and previous assessment period, and trends, are depicted
in Section III.D of this report.
The plant is generally operated conservatively and plant transients
are handled well. Plant operators are well trained, technically
knowledgeable, have demonstrated ability and are experienced. Improve-
ment in adherence to procedures is evident and must continue.
The performance in the area of radiological controls has degraded
during the current assessment period. A major contributing factor
was the heavy radiological work load during the Unit 2 outage. A
significant deficiency exists with regard to the ability to take
effective corrective action to prevent recurrence of identified
radiation protection problems. Also, the performance of security and
safeguards has degraded markedly. Deficiencies exist in the perfor-
mance of ouards in carrying out their duties as required by the
Security t'lan, and in licensee oversight of the contractor guard
force. Management involvement and development of improvement pro-
grams are warranted for these two areas.
Fire prctection and housekeeping controls have improved somewhat
during the current assessment period. Management continues to be
involved in this area, in particular during the lengthy outage
period during the assessment. Site QC remains involved in
identification of housekeeping deficiencies. Continued management
involvement in fire protection and housekeeping area is warranted.
B. Training Evaluation
The licensed operator training program (replacement and requalifi-
cation) functions well. Training of QA personnel was observed in the
area of QC inspectors and was evaluated as good. Mockup training for
specific maintenance activities is good. Inadequate training in the
area of radiological controls was identified in two areas: specific
training of chemistry technicians who perform radwaste surveillances
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and training of the Radioactive Material Coordinator.
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Training deficiencies were also identified for emergency plan person-
nel.
C. Quality Assurance Evaluation
Overall the QA organization is a itcensee strength. The licensee has
staffed the on site Electric Production Department (EPD) QC organt-
zation during the assessment period. Although, the QA organization
is somewhat fragmented, it functions well. Weaknesses were identified
in the Engineering and Research Department (E&R) QA system that tracks,
corrective action for audit findings. Also, deficiencies were identi-
fied in the radiological controls problem identification and correc-
tive actions. QA is evident in day-to-day plant operations as evi-
denced by QA personnel presence in the control room and in daily
plant operations meetings. QC is also evident in the performance of
plant housekeeping inspections.
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D. Facility Performance
Category Category Recent
Functional Area Last Period This Period Trend
{ March 1,1983 (January 1, 1984 to
to December 31,1983) March 31, 1985)
1. Plant Operations 2 2 Consistent
2. Radiological
Controls' 2 3 Consistent
3. Maintenance 2 1 Consistent
4. Surveillance 2 2 Consistent
5. Fire Protection &
Housekeeping 2 2 Improving
6. Emergency ,
Preparedness 2 2 Improving
7. Security and
Safeguards 1 3 Consistent.
8. Refueling /0utage
Activities 2 1 Consistent
9. Licensing Activities 1 1 Declining
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IV. FUNCTIONAL AREA ASSESSMENTS
4.1 Plant Operations (34%)
During this SALP period, resident inspections routinely reviewed
plant operations; specialist inspections reviewed QA and QC programs,
procurement, modifications, contractor controls, and response to
gener-ic issues.
Corporate and station management presence and involvement in plant
operations provides appreciation for plant technical problems. Review
of control room and plant activities and control room logs by on site
management is frequent. Corporate management is on site often as evi-
denced by attendance at meetings and discussions with on site manage-
ment personnel. Communications between groups in the plant appears
to be effective. No significant problems were noted with respect to
the level of decision making. Electric Production Department has
issued a " Requirement and Guidelines" manual to provide policy gui-
dance and clarify policy issues. Plant management has begun to issue
newsletters to keep all plant workers informed of significant hap-
penings and provide additional information which may be of interest
to workers.
As noted in previous SALP assessments, control room operators
response to plant transients was a strength and continues to be so.
Operators use the symptom-based emergency operating procedures
effectively. During a low probability event such as the earthquake
of April 22, 1984, the operator took the proper actions. Establish-
ment of the "Inside Supervisor" position, an SR0 in the control room
at all times has provided additional depth to the control room
capability. The STAS function well with the other shift members.
The operators work well with and respect the function of the STA.
The licensed operators take pride in their control room and related
activities. They are knowledgeable of overall plant status as exhibited
by documentation in the shift turnover checklists and personal inter-
views. There is no evidence of control room distractions. Noise
level is generally controlled so as not to interfere with control
room activities; however, there have been a few observed occasions of
shouting in the control room (not related to duties). Access to the
general control room area is restricted only by the vital area doors.
However, there are control room floor boundary tape markings where
access to the control room panels and c]ntrols is limited to autho-
rized personnel only. The overall control room appearance is good
with no evidence of inappropriate material. General area cleanliness
is also good.
Adherence to procedures and attention to detail in safety-related
equipment lineups have been generally adequate. However, there were
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several instances where lapses. occurred in following procedures, such
as exceeding heatup rate limits (Units 2 and 3), pressurizing the
reactor vessel above limits (Unit 3), mode switch in improper posi-
tion (Unit 3), and exceeding the torus water level limit (Unit 3). A
civil penalty was assessed for pressurizing the reactor vessel above
limits and exceeding the heatup rate. Another example of lack of
operator attention to procedural details occurred when the Unit 3
operators took a redundant safety system (HPCI) out of service before
permitted by technical specifications. The licensee took appropriate
corrective actions regarding safety system operability including
reinstruction of operators.
The licensee's return to power operations following outage periods is
generally smooth and well controlled. However, following the Unit 3
shutdown in February,1985, for maintenance and testing the return to
power operations was hindered due to problems associated with a main
steam safety relief valve, leakage from the drywell air lock and a
scram on loss of vacuum. The operators handled these problems profes-
sionally. At the time of the SALP board, Unit 2 continues to be shut
down in a refueling / outage period and related items for refueling /
outage activities are addressed in Section 4.8.
During June, 1984, an NRC Order Modifying License (see Section 5.2)
was issued. This Order resulted from the establishment of a licensee
practice of individually scramming control rods during controlled
shutdowns without adequate safety reviews as required by 10 CFR 50.59.
The individual rod scramming resulted in effectively bypassing the
functions of Rod Worth Minimizer (RWM) and the Rod Sequence Control
System (RSCS). The Order requires the licensee to perform an assess-
ment of the safety review process, to conduct a review of station
procedures and to ensure personnel involved in the procedure review
and approval process are aware of the licensing bases. The Operations
Analysis Corporation, the contractor who performed the safety review
process appraisal, concluded that the licensee's process for safety
evaluations was adequate. However, the existing controls for safety
reviews of procedure changes were determined to be ineffective. The
licensee's review of station procedures is currently ongoing with a
-scheduled completion date of September 1985. The licensee's review
of personnel qualifications associated with the procedure change
process was completed on February 25, 1985.
The on site review committee (PORC) appears to be functioning well
based upon observation by inspectors at PORC meetings. The Station
Superintendent appears to be utilizing the PORC in an effective
manner, as evidenced by the frequency of meetings and scope of
questioning of items brought before PORC. As an example, although
! plant procedures did not require PORC to review and approve the modi-
fication test results, PORC chose to review the completed Modifica-
tion Acceptance Tests as well as the test procedures for Unit 2. The
l PORC takes an active part in contributing to operational safety.
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Several strengths were noted in the licensee's overall QA programs.
These include the following: positive welder identification through
the use of photographs, more conservative requirements for the evalua-
tion of ASME NDE results, and independent audits of vendors previously
audited and accepted by a contractor. In response to the last SALP
assessment, the licensee has staffed the EPD site QC organization
with well qualified contractor personnel. Licensee personnel have
been selected for on-the-job training to fill the QC positions per-
manently. These personnel are currently one-on-one training with the
contractor personnel in order to qualify the licensee personnel for
the QC positions.
EPD QA routinely monitors shift turnover and control room activities.
Management involvement in QA is evident, staffing is adequate,'and
audit activities by the licensee are generally effective. However,
the E&R QA system for tracking corrective actions was noted to be
weak in that audit findings remained open for a long time. The multi-
departmental organization results in a somewhat fragmented QA program
whereby QA activities are divided among those departments. Despite
the fragmentation, the QA program is effective, but some implemen-
tation problems have been observed. For example, problems with the
storage of safety grade pipe, control over access to the storage
area, and mixing Q and non-Q items were identified. The licensee has
initiated corrective actions in this area, and this item will be
reviewed during future NRC inspections.
A well organized system is in place for tracking IE Bulletins which
results in adequate documentation regarding each item. The system
results in technically justified closeout when the reqd red actions
are completed. Implementation of the system indicates a large degree
of involvement and control by management. However, response to NRC
inspection issues is not always timely and limited management atten-
tion has been paid to this area. Additional management attention is
required to closeout open NRC inspection findings.
The LER process is adequate as demonstrated by NRC review of licensee
submittals. LERs are further discussed in Section 5.4.
No difficulty has been observed in obtaining the necessary records to
complete NRC reviews. Minor administrative errors were found in
the control of piping and instrument drawings (P& ids) and the main-
tenance of controlled copies of procedures. These problems identi-
fied were not of any major significance, however, it was determined
that Quality Assurance had identified similar problems in three pre-
vious audits (October 1982, November 1983, and February 1984), thus
indicating that in*tial licensee corrective actions were inadequate.
Subsequent corrective action in these deficient areas resulted in
overall improvements in document control.
r
16
The previous SALP assessment recommended that the licensee move for-
ward with the independent safety assessment activities. The licensee
has established a functional onsite Independent Safety Engineering
Group (ISEG). A concern with the simultaneous inoperability of the
containment cooling subsystem and one diesel generator resulted in
the licensee initiating a daily review by the ISEG of safety equip- '
ment out of service and the effect on plant operations. Further
licensee review of ISEG activities appears warranted to move clearly
' define its functions and responsibilities.
The licensee's training program has resulted in four operators and
three senior operators being licensed with only one operator
candidate failing an NRC written examination. In addition, three
candidates passed the senior operators examination as part of
intructor qualifications. No significant areas of weakness were
noted during the examinations and no suggestions for improvement
in training programs were made as a result of the examinations.
Overall, the licensee's replacement operator training program
appears to be satisfactory as evidenced by performance on NRC
administered examinations.
Conclusion:
Rating: Category 2
Trend: Consistent
Recommendations:
Licensee
Evalute the causes of the forced outages and unplanned scrams with
respect to plant operations, maintenance and testing activities.
NRC
Review licensee's actions from the appraisal plan recommendations
resulting from the NRC Order. Observe the offsite review committee
activities.
_ . - . _ . _ _ _
. __
, _ _ - _ .
17
4.2 Radiological Controls (9%)
Inspection efforts in this area included 10 inspections by Radiation
Specialists in the program areas detailed below. Day-to-day review
of ongoing activities was provided by the resident inspectors.
The overall area of radiological controls has degraded primarily due
to poor performance in radiation protection. Problems were noted in
several of the program areas reviewed. The Unit 2 pipe replacement
outage placed a strain on the radiological controls area. During the
previous assessment period, improvement frem Category 3 to Category 2
performance was noted. During this a m ssment period, programmatic
weaknesses were noted in radiat 6 protection and transportation.
Radiation Protection
Eight inspections, incitding six special inspections relating to the
piping replacement radittion protection program, identified problems
in the areas of training and qualification of personnel, in
procedural adherence and 10 assessment and control of radiological
conditions.
The licensee's radiation prctection supervisory personnel and quality
assurance activities were at times ineffective in problem identifica-
tion and correction. Responsibility for assessing the radiological
practices associated with on going radiological operations appeared
fragmented.
The apparent inability on the part of the licensee to take effective
corre tive action to prevent recurrence of radiation protection prob-
lems .3 of concern. In June and August 1984, the licensee did not
provide specific radiological exposure controls in radiation work
permits nor did they thoroughly evaluate radiological conditions
during the Unit 2 drywell work. In February'1985, the licensee again
did not provide specific radiological exposure controls in radiation
work permits nor did they evaluate the radiological conditions asso-
ciated with work on the "81A" valve of the RHR system. The corrective
action system did not recognize nor address a problem in radiological
controls involving valve "81A" on February 3, 1985. As a result, a
similar problem occurred on February 10, 1985 at the same valve with
a significant potential for serious radiation exposures to drywell
workers. At the March 4, 1985, Enforcement Conference, the licensee
presented additional management controls to address this concern for
recurring radiation protection problems. A number of immediate cor-
rective actions were implemented by the licensee, and reviewed as
being satisfactory by the NRC. Further improvements in this area
remain to be completed.
Occasional poor understanding of and adherence to radiation protection
procedures were noted. Examples include: correction factors were
not developed and applied to personnel mpnitoring devices; Health
<
'
18
Physics technicians, assigned to the piping replacement, were not
trained in four radiation protection procedures defining their duties
and responsibilities; dosimetry personnel did not receive formal
training and determination of their competency in the tasks assigned
to them; a radiation worker failed to exit the drywell promptly when
his audible-alarming dosimeter indicated his administrative dose
limit had been reached; several radiation workers entered valve "81A"
without adequate knowledge of the radiological status of their work
area; procedures for operation of the whole body counting system were
not provided; guidance for the issuance and use of extremity and
other supplementary personnel monitoring devices was not provided;
and, source checks for operability of audible-alarming dosimeters
used to control exposures in high radiation areas were not required.
Licensee corrective actions were implemented for each deficient con-
'ition. Corrective action for most of these items have been com-
p.eted and the review of the remaining items is pending.
The licensee's exposure control program is good as evidenced by main-
taining personnel radiation exposure within the estimates for the
Unit 2 refueling / outage. No personnel overexposures occurred during
the period.
-
'
The licensee's facilities and equipment were reviewed during the asses-
sment period and were found to be generally adcquate to support normal
and outage operations.
Management attention was directed to providing a defined ALARA program
to support Unit 2 piping replacement. During the planning and pre-
paration for the piping replacement, th piping replacement contractor
developed instructions for the pre-job planning to control radiation
exposures, mockup training for piping replacement personnel and radia-
tion exposure tracking throughout the operation. The licensee kept
abreast of other ALARA programs for BWR pipe replacement outages and
considered their experiences in Peach Bottom ALARA planning. The
licensee adopted the ALARA instructions and implemented them into
controlled station procedures. However, the licensee did not ade-
quately review the interface between the ALARA instructions and
existing station procedures. Two procedures, with differing require-
ments, were used to identify, report and correct radiological defi-
ciencies. When identified by the NRC, the licensee promptly took
action to make the procedures comparable.
Radioactive Waste Management and Effluent Monitoring
s
The review of the radwaste organizational structure indicated that it
was consistent with Section 6 of the licensee's Technical Specifica-
tions.
19
Two inspections, including the Operations Assessment Team Inspection,
identified several problems and weaknesses in the licensee's radwaste
program primarily due to an occasional lack of management attention
to detail to assure quality. No effluent release limits were exceeded.
The review of the licensee's selection, training and qualification
of personnel indicated a weakness in the training program to
maintain proficiency of the radwaste staff. The licensee did not
have a periodic retraining program for chemistry technicians
performing'sufveillance tests on liquid radwaste equipment.
Actions to ensure that safety evaluations were completed for con-
~
tractor-op'erated temporary radioactive. waste disposal operations to
support UnTt'2 pipe replacement were not taken by the licensee prior
to their arrival and setup for operation. When the lack of safety
evaluations"was identified by the NRC, the licensee took prompt
action to prevent waste disposal operations before the safety evalua-
tions were completed.
The review of the licensee's radwaste quality assurance program
indicated that audits of the radwaste program were performed in accor-
dance with licensee requirements. However, a problem with assuring
compliance with 10 CFR 61.56 was noted. In December, 1984, a cask
containing solidified resins from the Unit 2 pipe decontamination
released a flammable gas and a radioactive aerosol which resulted in
measurable contamination and intake of radioactive materials by two
workers. The Ticensee did not properly evaluate the generation of
the gas and its potential release during handling preparatory to ship-
ment. The licensee added precautionary measures for future radwaste
processes and has initiated a formal evaluation of the radwaste pro-
gram at Peach Bottom.
One Licen'ees Event Report (LER) was issued by the licensee in this
area (LER 2-84-06). In March, 1984, a leak in the "2B" RHR heat ex-
changer was discovered which resulted in a discharge of approximately
65 microcuries per day, and an estimated total release of 1,170 to
2,150 microcuries to the environment. The "2B" RHR heat exchanger
was repaired and returned to service.
'The licensee' implemented a program to reduce the amount of solid rad-
waste at the station. This program is referred to as " green is clean".
'(The clean' trash receptacles are painted green.) This program has
reduced the amount of solid radwaste generated on site.
~
Transportation
,
- An inspectio,n of the transportation program identified several
'p.oblems primarily due to an ineffective training program for the
lice,nsee's staff. The training program in transportation did not
.
!
[:
20
- properly train the Radioactive Material Coordinator.and non-licensed
operations personnel in NRC or DOT Regulations to assure that suit-
able proficiency was achieved and maintained. Non-licensed opera-
tions personnel were not trained in NRC and DOT Regulations and
appropriate procedures during-1981, 1982 and 1983 as committed to the
NRC-by the licensee in response to Bulletin No. 79-19. By December
1984, the Radioactive Material Coordinator, Shift Supervisors and the
non-licensed operations personnel had received training.
-The lack:of an effective training and qualification program in
transportation req'uirements and procedures was a major contributing
factor to an inade
tions and led to p'quate
roblemsunderstanding of theand
in classification transportation
certificationregula-
of ship-
ments. Three waste _ shipments identified were improperly classified.
The. Shift Supervisor certified that the shipments were properly
classified when they were not. The licensee revised the appropriate
procedures and counseled the individual involved.
Although the licensee's quality assurance audit program identified
the' lack of training, the audit-program for transport packages
did'not address the applicable criteria of a quality assurance
program for' transport packages as defined in Appendix B, 10 CFR 50.
This weakness suggests a lack of technical expertise in transport
package reviews conducted by the quality assurance organization.
Conclusion:
Licensee performance in radiological controls has degraded since the
last assessment period. Increased management attention is required
in work planning, training, procedures and corrective action.
Rating: Category 3
Trend: Consistent
Recommendations:
Licensee
Conside'r a third party audit and assessment of corporate and onsite
radiological controls and related activities.
'
NRC
Within six months, conduct a team inspection and perform an NRC
assessment of radiological controls. Conduct a licensee management
~
meetirig~ to discuss licensee actions and current status of the Peach
Bottom radiological control program.
,
21
4.3 Maintenance (8%)
Maintenance activities were reviewed during each resident
inspection. Various specialist inspections reviewed maintenance
and related activities during reviews of plant modifications,
responses to IE Bulletins, reviews of corrective and preventive
maintenance programs, and reviews of maintenance associated with
the Unit 2 pipe replacement outage.
Last assessment period maintenance was evaluated as Category 2.
Deficient areas included lack'of aggressiveness with respect to
minor maintenance items, maintenance performed using measuring and
test equipment that was out of tolerance, and inadequate overview of
vendor activities engaged in maintenance.
Overall, improvement was noted during the current assessment
period. Management is appropriately involved in the maintenance
programs and associated activities. The maintenance organizations
are well staffed with knowledgeable and experienced supervisors and
craft. Managem nt and engineering personnel are directly
involved in support of maintenance activities. Large maintenance
tasks are well planned and executed. Training and pre-job briefings
are conducted adequately in order to minimize the maintenance
activities' impact on overall schedule and to ensure that the
maintenance tasks proceed smoothly. This is evidenced by the
recent control rod drive (CRD) changeout at Unit 2. The maintenance
was well planned, training was given (including mockup training) to
individuals involved, pre-job-briefings occurred, the ALARA program
for the changeout was excellent, and problems were handled
adequately as they occurred. In all, the CRD changeout activity
and associated maintenance tasks went well and on schedule.
Maintenance is adequately conducted in accordance with administrative
procedures and specific maintenance procedures. Maintenance proce-
dures are detailed step by step and provide the maintenance techni-
cians adequate guidance. Administrative controls associated with the
Maintenance Request Form (MRF) are adequate. A problem was noted
however, regarding maintenance procedures directly referencing
drawings (i.e., part No.) that were not attached as required. Also
several maintenance division administrative procedures were identi-
,
'
fied as overdue for their periodic review. The licensee reviewed
these procedures,'and initiated revisions as necessary. NRC review
of licenseo action is pending.
An inspection was conducted to ensure that maintenance activities
are given proper review for the identification of equipment
failures, trends and root causes, and that the documentation systems
are organized to support evaluations. A computerized system for
maintenance management and documentation is now being used to
22
l
provide a better capability for researching equipment history and
for trending equipment failures. The licensee is adequately
addressing repetitive equipment problems and searching for the root
causes of failures.
Major equipment deficiencies continue to receive prompt and
appropriate attention consistent with safety and technical speci-
fication requirements. Examples during the assessment period
include safety relief valve failures, ECCS pump and valve mal-
functions, main steam isolation valve (MSIV) leakage and safety-
related instrument failures. Corrective maintenance is at times not
successful in repairing the deficient condition. However, problems
are detected during post-maintenance checkout and testing, and
repairs are initiated again. For example, additional repair of MSIV
seat leakage was required after initial repairs did not correct the
leakage.
During the assessment period, the licensee completed the development
of an upgraded preventive maintenance (PM) program and began its
implementation. This PM system has the capability to provide
feedback information for maintenance procedure revision.
Control of major modifications by the use of a Construction Job Memo
is effective for simple modifications. The Construction Job Memo
details the scope of work and references drawings, specifications and
construction procedures and appears to be implemented effectively.
More complicated modifications are controlled by the use of work
instructions for each item of the modification.
Personnel are well qualified and familiar with the work
demonstrating an effective training program. QA/QC training
regarding applicable procedures is provided. Strong management
involvement and control is demonstrated by continuing surveillance
and coordination by licensee personnel. An example of this was the
torus modification requirements and work procedures which were
clearly established and well organized. Hold points for QC and ANI
inspection were clearly identified.
Management involvement was further demonstrated by the issuance of
general and special instructions which controlled the work. Doc-
umentation for completed work was readily available and complete.
Changes are closely controlled, approved by engineering and
independently reviewed.
1 The long delays associated with the documentation of change approval
'
points out a need for increased management attention in this area.
Further evidence of the need for increased attention was identified
in the case of electrical modifications where installation drawings
were found to lack sufficient detail for their intended use and
~
inexperienced personnel reviewed those drawings.
_ _
23
Evidence of strong management involvement was identified in the
areas of post maintenance testing. Test requirements are reviewed
by management,-testing is completed in a timely manner and the
licensee's tracking system assures that testing is completed prior
to system startup.
-In summary, maintenance is well planned and performed in accordance
with procedures. Management is involved in all aspects of
maintenance activities.
Conclusion:
Rating: Category.1
Trend: Consistent-
Recommendations:
Licensee
None
NRC
None
24
4.4 Surveillance (3%)
In the current assessment period, one region-based inspector
conducted an inspection of the containment local leak rate test
program. Specialist inspections by region-based inspectors also
reviewed surveillances applicable to health physics, fire
protection, refueling equipment, maintenance activities, snubbers,
emergency preparedness, and environmental monitoring. Resident
inspectors reviewed selected program areas each month.
The previous assessment period noted the following problems
regarding surveillance test activities: improper restoration from a
calibration procedure resulting in primary containment integrity
degradation, use of incorrect revisions of surveillance test
procedures, and programmatic weakness with the control of measuring
and test equipment.
Inspections during this period confirmed that the surveillance
testing programs are technically sound and generally well planned.
Staffing of the various groups responsible for conducting sur-
veillance testing appears adequate. Surveillance test procedures
continue to be systematically upgraded to provide for better
control, improved documentation, and independent verification as an
integral part of the procedure. Management involvement is evident
in ensuring that changes to surveillance requirements, such as those
resulting from Technical Specification Amendments, are properly
implemented.
Some !mplementation problems associated with the surveillance test
program occurred during this assessment period. These problem areas
were associated with the escalated enforcement action early in
assessment period, and are as follows: surveillance tests not
completed after the tests had begun, specific steps required by TS
not denoted as such, inadequate review of r rveillance results by
technical personnel and failure to follow a surveillance test
procedure. These deficiencies, along with other problem areas, are
currently being addressed in the licensee's response to the NRC
Order of June 18, 1984. Surveillance procedures are being reviewed
by an appraisal team as required by NRC Order (Section 4.1).
Quality Assurance (QA) involvement in surveillance is generally
appropriate. QA audits include a broad scope review of completed
surveillances. Surveillances are observed during audits of indi-
vidual functional areas.
Containment local leak rate testing (LLRT) for Unit 3 was reviewed
in detail during the assessment period. LLRT is generally per-
formed in accordance with appropriate test procedures, with
calibrated instrumentation, by qualified test personnel and with
adequate QC monitoring. One area of concern was identified with
regards to the licensee's method of tracking and computing as found
leak rate value at time of plant shutdown.
__
25
The existing method does not adequately demonstrate compliance with
10 CFR 50, Appendix J, combined local leak rate test acceptance
criteria. License review of this calculational method is in
progress.
In summary, although problems were identified early in the
assessment period, the surveillance program has improved, with
further-improvement attainable through the following: continued
management, supervisory, and QC attention _ to upgrading of attention
to detail, especially with respect to equipment lineups; and
supervisory and management attention to the thorough review and
evaluation of test data, as well as to identification and
correction of deficiencies in the approved procedures.
Conclusion:
Rating: Category 2
Trend: Consistent
Recommendations:
Licensee
Increase management, supervisory and QC involvement in surveillance
test conduct, test review, system restoration and procedure upgrades.
NRC
None
[.
i
I
'
_
26
4.5 Fire Protection / Housekeeping (1%)
In the current assessment period, fire protection and housekeeping
was reviewed during one specialist inspection and as part of each
resident inspection.
During the previous assessment period the licensee made significant
improvement in the areas of housekeeping and in plant fire
protection. Fire brigade training, fire barrier integrity,
maintenance and coordination of the fire protection program were
identified as areas requiring improvement and increased management
attention.
During the current assessment period continued efforts of manage-
ment to maintain good housekeeping and fire protection controls were
apparent. Management administrative controls were strengthened and
changes were incorporated to increase monitoring activities
regarding fire brigade personnel training which resulted in
maintaining the required level of training. Additionally,
procedures were revised to reflect the requirements of current
regulations and the present site organization. The site position of
Fire Protection Coordinator which had been vacant for sometime, has
been filled.
A continuing weakness that is evident is the maintenance of fire
barriers. This is attributed to a lack of management attention in
the pursuit of resolutions to related issues. This is evidenced
by the following conditions noted regarding fire doors: door
closer not working properly, doors found open and unlisted doors (UL
label missing).
Access to fire fighting equipment stations was identified as a
problem area during previous assessment periods. One instance
of blocking fire extinguisher access was noted during this assess-
ment period on the Unit 2 refueling floor. The licensee subsequently
installed fire equipment location signs on both units' refueling
floors.
During the annual emergency exercise, the scenario included a fire
in the auxiliary boiler building. This required activation and
response of the on-site fire brigade, and assistance of the off-site
fire organization. The fire brigade responded promptly to the fire
scene and there were excellent coordination and strategy discussions
between the fire brigade leader and the off-site fire chief. Minor
exercise deficiencies were noted and were corrected by the licensee.
With Unit 2 in a pipe replacement / refueling outage during 11 months
of the assessment period and during other outages associated with
Unit 3, housekeeping conditions were monitored closely. A few small
fires occurred that were associated with poor housekeeping activities.
_
27
The site QC group was given responsibility for evaluating house-
keeping and they appeared to be effective in early identification
and resolution of housekeeping discrepancies. Housekeeping
.
conditions, noted problem areas and corrective actions were
routinely discussed at the daily and weekly outage meetings.
During the special Operations Assessment Team Inspection for Unit 2,
noted deficiencies in the drywell regarding housekeeping and tool
-
control were observed. Specific problems included: small tools
scattered about, metal machining chips not collected, removed
mirror insulation left laying around, and hoses strewn about.
These conditions increased the possibility.of the instrusion of small
items into piping systems, contaminated injury to workers and other
unwarranted conditions. When these items were brought to the atten-
tion of the licensee, drywell work was stopped and a general area
cleanup was immediately conducted. Subsequently, the drywell con-
ditions were monitored periodically and found to be acceptable.
Overall, fire protection and housekeeping has improved. Continued
management attention to the identified weak areas will lead to
further improvements.
Conclusion:
Rating: Category 2
Trend: Improving
Recommendations:
Licensee
Maintain senior corporate and station management attention toward
good housekeeping and fire protection habits at the station and seek
methods for further improvements in this area.
NRC
None
__ . _ . _ _. . _ _ _ ___ _ ._ _ __
. _
$
28
4.6 Emergency Preparedness (10%)
Two region-based inspections were conducted during the assessment
period, including the annual emergency exercise. The resident
inspectors monitored the licensees' performance throughout the
period.
During the previous assessment period, inadequacies were identified
in the management review and administrative followup of emergency
preparedness training programs. Significant weaknesses were '
. identified in the Health Physics area during the June 1983 exercise.
A confirmatory letter was issued outlining the corrective action
commitments. A successful remedial in plant Health Physics drill was
observed by the NRC in August 1983.
During this assessment period, an annual full participation emergency
exercise was conducted in October, 1984. The area of Health Physics
control improved significantly compared to the previous exercise. A
weakness with the review of procedures for compatibility with pla'nt
equipment was identified during the exercise. The emergency
procedure which identified emergency action levels based on the
reactor building and main stack radiation monitors specified
emergency action levels that were above the full scale capabilities
-
of the associated radiation monitoring instrumentation. The licensee
modified the appropriate emergency procedure and the NRC found the
procedure acceptable.
A subsequent inspection in January 1985 identified problems in 3
areas. Personnel were identified who did act have all of the
' required training for the positions in the emergency organization to
which they were assigned. Appendices to the emergency plan, which
contain the names and telephone numbers of personnel to be contacted
in an emergency, were 17 months overdue for updating. Some names and
numbers were incorrect. The third weakness was the licensees audit
program which did not follow up on previously identified deficiencies
in the emergency preparedness area. Licensee corrective actions and
NRC review of the actions, are pending.
The licensee.is currently revising and updating the emergency plan
procedures and training program. A permanent site Emergency
Preparedness Coordinator position has been established rather than a
rotating 1 year assignment. A strengthened corporate management
involvement has been apparent in recent activities.
Conclusion:
.
Rating: Category 2
Trend: Improving
. __ _ _. . . - . _ . _ _ __ _ _ - . _ _ _
. . . . . -_ ..... .. .. . . .... - . , -- . - . .
,
.
29
.
Recommendations:
-
-
Licensee
,
~
~
Continue current level of. corporate management' involvement to further
m improve.this area.
. NRC'
None
,
t
'
?
4 ,
d
-
1
%
i
1-
.
t
4
e
$
&
e -,.e , - - - . ,.e,, . - - . - ..e-- , , ,,,-,..,.w-,4-,,r.w.,--, , ,_,en,,. . _ , .- - awr,,, , . , ,,, , . ,, -,,,_,.g.,,,,_,.m, , - ,
_
30
4.7 Security and Safeguards (4%)
Three unannounced physical protection inspections were performed
during the assessment period by region-based inspectors. Routine
resident inspections continued throughout the assessment period.
During June 1984, with Unit 2-in a major outage, a physical security
inspection noted. numerous problems and an enforcement conference
resulted. NRC inspection findings were addressed by the licensee
during the enforcement conference and actions to prevent recurrence
for several issues were provided at that time. More complex issues
required additional review and actions by the licensee in order to
develop appropriate corrective actions. The security problems were
cumulatively cited at the Level III severity for the licensee's
failure to exercise proper supervision and oversight of the contract
guard force.
In reviewing the security deficiencies that were observed during the
outage, of particular concern was the fact that members of the
security force did not respond to alarms in vital areas of the
plant. The failure to respond to alarms was compounded by the fact
that the capacity of the security computer to monitor alarms had
been reached. Security force members apparently did not recognize
the seriousness of the problems nor did they escalate their
awareness that the problems existed. Neither the contract security
supervisors nor licensee management were providing sufficient
oversight of the guard force; and, they were either unaware of or
did not recognize these events as a serious security system
breakdown. Further, the contractor's security supervisors and
licensee security management were aware of the potential for the
computer overload problem, but did not provide for this
contingency'and take the appropriate corrective action.
The need for an assistant site security supervisor position was
recognized by the licensee prior to the outage. However, the
licensee management failed to give adequate priority to the filling
of this position. As a result, a position essential to maintaining
licensee oversight of the contract guard force, particularly
important during a major maintenance outage, was not filled. This
vacancy, along with the resulting poor corporate and site security
management oversight during the outage, are considered to be the
major contributors to the security program problems identifed during
a June, 1984 inspection. However, security program implementation
during periods of routine plant operation was considered adequate.
The security contractor's general performance level decreased
considerably since the last assessment period, as evidenced by the
problems involving ineffective supervision, personnel not
following procedures and inadequate response to alarms. Also, the
quality of security force training appeared to have decreased or
-
N
31
was less effective during this period, as evidenced by an increase
in personnel errors. This may have been exacerbated by inadequate
management attention.
Seven security event reports were submitted pursuant to the
requirements of 10 CFR 73.71. Three reports pertained to computer
failure, three described security personnel errors (two involving
placement of vital area doors in access, and the other, a guard
intentionally alarming a zone), and one involved evacuating the
Central Alarm Station because of a fire protection system alarm.
Although all events were adequately handled, the three events
involving personnel errors could have resulted in undetected
access to vital areas. Further, the report describing the CAS
evacuation was inaccurate as initially submitted. NRC review of
the incident revealed that the inaccurate report was the result of
_ poor communication between the site security supervisor and contract
security management and inadequate follow-up of the incident by
security management. A corrected report was subsequently submitted.
The licensee was responsive to regional concerns and to questions
regarding 3 revisions to ths Security Plan and 1 revision to the
. Training and Qualification Plan. The format and content of these
revisions were considered satisfactory.
Conclusion:
Rating: Category 3
Trend: Consistent
Recommendations:
Licensee
Increase licensee management oversight and control of the contractor
security force on a day-to-day basis. Provide for periodic assessment
of the adequacy of program implementation.
NRC
Resident Inspectors provide monitoring of improvements for licensee
actions. Region I perform a programmatic review of security and safe-
guards within 6 months to assess licensee performance.
32
4.8 Refueling /0utage Activities (31%)
In the current assessment period, both units experienced outages.
Unit 2 was shutdown on April 28, 1984, to replace recirculation
system and RHR system pipe inside the drywell and to refuel. A large
number of other modifications were done while Unit 2 was down. The
unit has been out-of-service from April 28, 1984, through the rest of
the SALP report period. Unit 3 was shut down in February 1985, for
about three weeks to conduct required maintenance and surveillance
testing. This assessment focuses on the Unit 2 activities which have
been extensive. The outage required large numbers of support per-
sonnel, both licensee and contractor. During this time staffing
appeared adequate except for isolated security and radiation protec-
tion areas discussed in Sections 4.2 and 4.7, respectively. Inspec-
tions did not reveal any problems with lack of adequate staffing
during the outage.
Aspects of outage activities assessed during this period included QA
and QC, modification control, modification acceptance testing, ALARA
activities, welding, purchasing, ISI, NDE, control of contractors,
committee (PORC) activities, management control and involvement,
procedural adequacy and adherence, planning, audits, and response to
generic issues. The inspections found that the technical aspect of
the pipe replacement activities is a strength.
Pipe replacement management personnel were actively involved in the
project. Daily outage meetings and biweekly Project Review Meetings
were held to keep all management knowledgeable of the project.
Contractor site management was intimately involved in day-to-day
program activities. The licensee's project engineers were found to
be knowledgeable of day to day activities of the contractors and
interfaced well with corporate, site and contractor personnel. Early
in the project it was determined that contractor specifications were
used for procurement prior to obtaining licensee approval and this
caused some problems. The licensee indicated that he had reviewed a
draft of the specification to assure compliance with the ASME code
and later made changes which were enhancements beyond the Code re-
quirements. The prior approval of draft specifications caused the
problem with the weld buildup, since the specification enhancement
prchibited buildup, on pipe pieces received by the licensee. The
licensee initiated corrective action to evaluate each pipe piece for
conformance to code and specification requirements.
Management involvement and control in assuring quality was demons-
trated by the decisions regarding surface conditioning of the replace-
ment pipes to aid in ultrasonic examination results interpretation.
Further control was evidenced by the establishment of plans and sche-
dules to assure an orderly progression of the work activity and to
assure that ASME code requirements were met regarding preservice
inspection. In the area of nondestructive examination management
!
33
control was demonstrated by the thoroughness and effectiveness of the
licensee audits which in two separate instances, identified vendor
errors regarding radiographic film interpretation.
The licensee shows strength in the resolution of technical issues
from a safety standpoint. The licensee implemented Quality Assurance
provisions that exceeded requirements in a number of instances. For
example, they added more conservative requirements to the contractors
ASME approved QA program in that they required the contractor to
include safety related nonpressure retaining parts in the ASME program.
The licensee also places a strong emphasis on QA observations, at
random times, of on going activities.
During this assessment period, the licensee has been responsive to
NRC initiatives. The staff had identified a concern regarding the
lack of provisions taken to assure that all plant systems and com-
ponents that could be impacted by the pipe replacement program were
in acceptable condition prior to restart. The licensee formed an
experienced team (Major Outage Recovery Effort - MORE Team) of
engineers to be responsible for the activities associated with re-
storing to service drywell components and systems affected by the
outage. The MORE Team has developed a comprehensive set of tests to
cover all drywell activities and systems. In addition, the MORE
Team verified that components and systems were satisfactory and indi-
cated that CBI, PECo construction and PEco Electric Production were
all planning drywell walkdowns to check out components. The MORE
Team activities adequately addressed the NRC concern.
During the core alteration phase of the outage, operators were not
aware of a procecural requirement to verify refueling interlocks but
when the licensee was informed, he issued a comprehensive " shift-
meeting notice" dealing with responsibilities of operators during
core alterations. When concerns were identified regarding the ALARA
aspects.of replacement work on the N-2 nozzles the licensee stopped
all work on the nozzles until a decision was made on nozzle replace-
ment. The ALARA concerns were adequately addressed and nozzle work
resumed.
Training and personnel qualifications of outage workers were in
general good, because of the high standards set by the licensee.
Welders and NDE personnel were normally qualified to higher levels
than called for by the specifications. In addition, the licensee
E made extensive use of mockups for training and qualification which
helped keep radiation exposure within the outage specific ALARA
guidelines.
_ _ - . _ _ . ._- ____ __-_ _ ____ . ____.. . _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
34
Maintenance of industrial and fire safety during the outage has been
adequate. There have been relatively few accidents during the
outage. Fires have been minor and handled effectively by the
licensee.
Conclusion:
,
Rating: Category 1
, Trend: Consistent
Recommendations:
Licensee
None
NRC
Continue routine inspection of recovery activites and provide
specialist inspectors for Unit 2 restart activities.
.
i
- . , --, ,. -
-e- 9. - , ,- , ,-,-,-,.,e , - - , , - , . . - , . . - . , , - - . . - - . , . . . , - - , . , , - - - - , - - , .
- ~.
r.-
-
35
4.9 Licensing Activities
The approach used for this evaluation was to select a number of
licensing issues which involved a significant amount of staff effort
or which related to important safety or regulatory issues for the
period from January 1, 1984 to March 31, 1985. In most cases the
staff applied the evaluation criterion for the performance
attributes based on their first hand experience with the licensee
or with the licensee's submittals. This areas was rated as Category
1 during the previous assessment.
Actions during this period included licensee requests for license
amendments, responses to generic letters, and various submittals of
information for multi plant and NUREG-0737 actions. Active actions
during this period are classified below. A total of 74 licensing
actions were completed as noted in Table 6. In addition to these
specific issues, the licensee was evaluated for overall general per-
formance in the many day-to-day issues which arise.
In general, the licensee's management participated in licensing
activities in a manner appropriate for the significance of the
issue. There has been strong management involvement concerning
licensing activities pertaining to Unit 2 pipe replacement and
continued oversight of the Appendix R Fire Protection Program.
A trend developed in this period where management involvement
and control did not appear to be fully functional. One
such example was a TS change request pertaining to an exemption
from local leak rate testing of MSIVs which appeared to indicate
poor planning and assignment of priorities. Another area where
management involvement appeared to be lacking is the overall plan
and design of the Safety Parameter Display System (SPDS) where the
proposed SPDS has not met the minimum guidance of NUREG-
0737, Supplement 1.
The licensee's approach to issues has been both technically sound
and thorough in almost all cases. Resolutions are timely in almost
all cases and conservatism is routinely exhibited when a potential
for safety significance exists. The licensee's approach to
equipment qualification, post-accident sampling, and increased core
flow TS changes all showed above average, technical approach and
resolutions during this period.
However, in the last 6 months of the assessment period, there has
been a noticeable decline in the licensee's usually timely response
and resolution of licensing issues. This decline apparently coincided
with the increased activity in licensing activities at Limerick. The
licensee should give more attention to the structuring of its licensing
staff in order to accommodate the addition of the Limerick facility as
an operating plant.
g-
'
l
36
Also, the licensee should give more attention to the significant ,
hazards consideration determination that are submitted with each TS
change request. Specifically, the licensee should prepare more
explicit arguments for each of the criteria that must be addressed
.in reaching a significant hazards determination and thereby reduce
L
the time required to publish the Federal Register pre-notice.
- The licensee has continued to show a highly effective tracking
system for responding to NRC requests and almost always alerts
the staff in a timely fashion when an extension to a particular
submittal is needed. Generally, issues are resolved in a timely
'
fashion with acceptable resolutions proposed initially in most
cases.
Conclusion:
Rating: Category 1
Trend: Declining
Recommendations:
'
Licensee
, None.
NRC
None.
l
l
l
i
l
'
!
i.
, _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ . _ _ _ _ _ _ _ _ _
37
V. -SUPPORTING DATA AND SUMMARIES
5.1 Investigations and Allegations Review
NRC Region I received and evaluated four allegations during . e
assessment period. The allegations are summarized as follows:
--
CAS attendant overloaded with administrative duties and impact on
security job.
--
Contractor and licensee not meeting ALARA requirements.
--
Poor security practices effecting HP programs.
--
Deliberate misuse of emergency sirens.
5.2 Escalated Enforcement Actions
1. Civil Penalties
--
Notice of Violation and Civil Penalty of $30,000.00 dated
June 18, 1984 associated with violations (Enforcement Action
84-39) regarding excessive heatup rates, an unplanned reactor
pressurization, and excessive rod scram times.
2. Orders
--
Order dated June 14, 1984, confirming commitments to
implement Suaolement 1 to NUREG-0737, " Requirements for
Emergency Re:,ponse Capability" based on commitments to NRC
Generic Letter 82-33 dated December 17, 1982.
--
Order modifying license dated June 18, 1984, regarding
violations associated with Enforcement Action 84-39 requiring
the licensee to submit and implement a plan for an appraisal
of: (1) the process for performing safety evaluations and
reviews of procedures pursuant to 10 CFR 50.59 to determine
if the process is currently effective, or if improvements are
needed; (2) plant and system operating procedures to verify
that existing procedures are consistent with technical
specification bases, and those sections of the FSAR
concerning systems necessary to mitigate Design Basis
Accidents, and do not involve unreviewed safety questions;
and (3) the program for ensuring that employees
involved in the review and approval of operating procedures
remain cognizant of the licensing bases.
3. Confirmatory Action Letters
None.
-- - - . - - - - - - - - - - - - - - - - - - - - _ - - - - - - - - - _ - - -
,
38
4. Enforcement Conferences
-
An Enforcement Conference was held to discuss the findings of
Inspections 50-278/83-32, 50-277/84-01, 50-278/84-01, 50-
277/84-03 and 50-278/84-03 relative to individual rod
scramming and LCO violations on April 12, 1984.
-
An Enforcement Conference was held to discuss the findings of
Inspection 50-277/84-19 and 50-278/84-10 relative to security
plan violations on July 31, 1984.
-
An Enforcement Conference was held to discuss the findings of
Inspection 50-278/85-07, a Unit 3 event regarding simultaneous
diesel generator inoperability and containment cooling on
February 8, 1985.
-
An Enforcement Conference was held to discuss findings of a
radiological event during the Unit 2 outage from Inspection
50-277/85-11 on March 4, 1985.
5.3 Management Conferences Held During the Assessment Period
1. SALP Management Meeting at Peach Bottom Atomic Power Station
on March 2, 1984.
2. Management meoting to discuss licensee plans and controls for the
Unit 2 piping replacement outage on April 5, 1984.
5.4 Licensee Event Rrnorts (LERs)
Forty-one LERs were submitted during the assessment period. The 17
LERs for Unit 2 and 24 for Unit 3 are characterized by cause in Table
1. LERs reviewed include 84-01 through 84-16 and 85-01 for Unit 2;
and, 84-01 through 84-16 and 85-01 through 85-08 for Unit 3. Four
causally-linked event sets were identified:
-
Five LERs (3-85-01, 3-84-13, 3-84-15, 3-84-16, 3-85-04) all
involved inoperability of the HPCI turbine due to the inner
rupture disc (PSD-3-23-6) failure for Unit 3.
!
-
Three LERs (2-84-10, 2-84-16, 3-84-08) involved pipe cracking
indications for Units 2 and 3.
-
Eleven LERs (2-84-03, 2-84-07, 2-84-09, 2-84-15, 3-84-02, 3-84-06,
3-84-07,3-84-10,3-85-02,3-85-06,3-85-08) involved events
caused by personnel error. The errors were due to operating,
maintenance and test personnel.
-
Five LERs (2-84-01, 3-84-03, 2-85-01, 3-85-05, 3-85-03) involved
equipment failures encountered during surveillance testing.
I
39
The Office for Analysis and Evaluation of Operational Data (AE00)
assessed the Licensee Event Reports (LERs). The review covered a
majority of the LERs submitted during the assessment period. The
LERs submitted were adequate in each important respect with few
exceptions. All the LERs provided an abstract followed by:
(1)' description of the event, (2) consequence of the event, (3) cause
of the event and (4) corrective actions. The LERs provided clear
descriptions of the cause and nature of the events as well as-
adequate explanations of the effects on both system function and
public safety. The described corrective actions taken or planned by
the licensee were considered to be commensurate with the nature,
seriousness and frequency of the problems found. Table 1
provides additional observation from the AE00 review of the LERs.
In summary, the LERs indicates that the licensee provided adequate
descriptions of the events . None of the LERs reviewed involved
a significant event or serious challenge to plant safety.
5.5 Forced Outages and Unplanned Scrams
1. During the assessment period, Unit 3 experienced five unplanned
automatic scrams. As Unit 2 was in a refueling / pipe replacement
outage for the majority of the time, no unplanned automatic scrams occurred. Table 5 summarizes these scrams.
2. During the assessment period, the following unit forced outages
occurred:
--
Unit 2 - 5 forced outages, including 2 power reductions and
I shutdown for refueling.
--
Unit 3 - 19 forced outages, including 14 power
reductions / load level drops.
Table 5 summarizes these outages.
.
_ -- _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .____ _
_
'
l
T1-1
TABLE 1
TABULAR LISTING OF LERs BY FUNCTIONAL AREA
PEACH BOTTOM ATOMIC POWER STATION
Area Number /Cause Code Total
'1. Plant Operations 7/A, 2/B, 1/0, 7/X 17
2. Radiological
, Controls IX 1
-v 3. Maintenance 2/A, 2/X 4
4. Surveillance 4/B, 2/E, 4/X 10
5. Fire Protection 1/A, 1/B, 1/D, 2/X 5
, 6. Emergency
Preparedness 0
7. Security and
Safeguards 0
8. Refueling / Outage
Activities 1/A, 3/X 4
9. Licensing Activities 0
TOTAL 41
Cause Codes:
A - Personnel Error
B - Design, Manufacturing, Construction, or
Installation Error
C - External Cause
D - Defective Procedure
E - Component Failure
X - Other
AE00 Review of LERs
.The AEOD review of LERs included the following:
For Peach Bottom 2: 84-001 through 84-016 and 85-001
For Peach Bottom 3: 84-001 through 84-014 and 85-001 through 85-005
The LER review covered the following subjects and the general instructions of
~NUREG-016. The SALP review is presented with the topic review followed by
comments on that topic.
1. Review of LER for completeness
(a) Is the information sufficient to provide a good understanding of the
event?
The LERs provided sufficient data to give clear and
adequate descriptions of the occurrences, their direct consequences,
_ _ _. _ _ _ __ _ _ _ _ _ _ _ . _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ -
,.
T1-2
, Table 1 (continued)
root causes, and where known, corrective actions needed to prevent
recurrence.
-(b) Were the LERs coded correctly?
All coded entries reviewed appeared to be correct. However, there
were six LERs which did not specify the. failed component and
component manufacturer. These LERs were: 84-007,84-009,
84-013 and 84-014 for Peach Bottom 2; and 84-004 and 84-014
for Peach Bottom 3.
(c) Was supplementary information provided when needed?
Most of the LERs reviewed contained supplementary information.
The supplementary information provided was clear, concise and
adequate.
(d) Were follow-up reports promised and submitted?
The licensee submitted a follow-up report in every case reviewed
where such a commitment was made.
(e) Were similar occurrences properly referenced?
The licensee appropriately referenced similar prior occurrences
as necessary.
2. Multiple Event Reporting in a Single LER.
The licensee did not report any multiple events in a single LER.
3. Prompt Notification Follow-up Reports.
The region issued one PN for Peach Bottom 2 and three PNs for Peach
Bottom 3 during this review period. Two of the PNs issued should be
followed by an LER. Our review indicates that the licensee did issue
LERs84-008 and 84-011 for these two PNs. Both of these LERs were for
Peach Bottom 2.
In summary, the review indicates that based on the stated criteria, the
licensee.provided clear and adequate event reports during the assessment
period. No significant deficiencies were found in the LERs reviewed.
p
T2-1
' TABLE 2
VIOLATION SUMMARY (1/1/84 3/31/85)
PEACH BOTTOM ATOMIC POWER STATION
A. NUMBER AN0 SEVERITY LEVEL OF VIOLATIONS
Violations
B. - VIOLATION VS FUNCTIONAL AREA
Severity Level
Functional Area
III IV V
1 -Plant Operations 1 6 2
2 Radiological Controls * 0 7 3
3 Maintenance 0 1 1
4 Surveillance 0 0 1
5 Fire Protection / Housekeeping 0 3 0
6 Emergency Preparedness ** 0 1 0
7 Security and Safeguards 1 1 0
8 Refueling / Outage Activities 0 0 0
,
9 Licensing Activities 0 0 0
- Inspection Report 85-11 issued, enforcement action pending as of May 13, 1985.
- Inspection Report 85-03 not issued as of May 13, 1985.
= _ _ - - _ _ _ _ _ - _ - _ - - _ _ - _ _ _ _ _ _ - _ _ _ . - _ _ . _ . - . _ _ - _ . _ _ - .
. - -
.
T2-2
-Table ~2(continued)
C. SUMMARY
Inspection ~ Inspection . Severity Functional
' Report No. Date Level Area Violation
Unit 2 Unit 3
84-01 84-01 -1/5-20/84 III-CP* 1 Excessive heatup
rate, reactor
vessel pressuriza-
tion and excessive
rod scram times.
84-03 84-03 1/13-2/29/84 IV* 1 Operational pro-
cedural violations
84-02 84-02 1/16-20/84 IV 3 Failure to
adequately control
plant modification
activities.
84-03. 84-03 1/13-2/29/84 IV 5' Failure to
implement an
adequate fire
hydrant
maintenance
program
84-03 84-03 1/13-2/29/84 IV 1 Failure to report,
,
document and
properly disposi-
tion a
non-conforming
condition for the
torus vent header
84-07 84-07 3/1-4/20/84 IV 1 Failure to follow
SBGTS operating
procedure
84-07' 84-07 3/1-4/20/84 IV 7 Failure to
adequately control
a vital door area
84-08- 84-08 3/26-30/84 V 1 Failure to provide
adequate correc-
tive action
,
._. _ ._ --_- __ ________ _ ____ _ - _______- - __
.
T2-3
Table 2 (continued)
Inspection Inspection Severity Functional
Report No. Date Level Area Violation
Unit 2 Unit 3
84-09 84-09 3/26-29/84 IV 2 Failure to
,~
properly label
packages on radio-
active waste
84-09 84-09 3/26-29/8'4 IV 2 Failure to train
to NRC and DOT
guidelines
C4-09 84-09 3/26-29/84 V 2 Failure to verify
that shipping
manifests were
accurate
84-14 84-12 5/7-11/84 IV 1 Failure to provide
adequate cor-
rective actions
for audit and in-
spection findings
84-15 84-13 4/21-6/7/84 IV 2 Failure to post a
contaminated area
84-16 84-14 5/8/84 V 2 Failure to have
written approved
procedures for the
whole body
counting system
84-17 84-15 5/14-18/84 V 3 Failure to permit
evaluation of a
systems / components
performance
84-17 84-15 5/14-18/84 V 4 Failure to take
prompt corrective
action for sur-
veillance test
84-18 6/18-21/84 IV 2 Failure to train
HP technicians
,
. _ .
_ _ _ _ _ . _ _ ___________ _ _ -
T2-4
'
, Table 2 (continued)
Inspection Inspection Severity Functional
Report No. Date Level Area Violation
Unit 2 Unit 3
84-18 6/18-21/84 IV 2 Failure to pro-
vide specific
radiological
exposure controls
for RWPs
84-19 84-10 6/25-7/1/84 III** 7 Security plan
violations
84-20 84-16 6/8-7/15/84 IV 5 Failure to pro-
vide adequate
fire equipment
access
84-20 84-16 6/8-7/15/84 IV 1 Failure to
maintain adequate
document control-
84-22 7/16-20,23- V 1 Failure to main-
27/84 tain certification
requirements for
QC irspectors
84-24- 84-20 7/16-8/31/84 IV 1 Failure to perform
written safety
evaluation
84-25 84-21 7/20-23/84 V 2 Failure to follow
TLD procedures
84-31 84-25 9/1-10/10/84 IV 2 Failure to post a
-
- radioactive con-
taminated area
84-33 84-27 10/16-18/84 IV 6 Failure to provide
accurate
initiating con-
ditions for
emergency action
levels of
, _ . _. _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ - _ _ _ _ - _ _ . . - _ _ _ _ _ _ _ _ _ __ __ __-_-_.
_
T2-5
Table 2 (continued)
Inspection Inspection Severity Functional -
Report No. Date Level Area Violation
Unit 2 Unit 3
84-40 84-19 12/10-13/84 IV 5 Failure to main-
tain fire barrier
integrity
84-42 84-34 12/17-21/84 IV 2 Failure to provide
a QC program for
radwaste shipments
85-03 85-03 1/8-11/85 XXX 6 Two potential
violations
associated with
training and
updating
emergency noti-
fication phone
lists.
85-11 2/13-15/85 XXXX 2 Potential
violations
associated with
radiation
protection and i
radiological
controls
- EA 84-39 -
- EA 84-94
XXXInspection Report not issued as of May 13, 1985
XXXXInspection Report issued, enforcement action pending as of May 13, 1985
w___
T3-1
TABLE 3
INSPECTION REPORT AiCTIVITIES (1/1/84 - 3/31/85)
PEACH BOTTOM ATOMIC POWER-STATION
Reoort Inspection Hours Areas Inspected
Unit 2 Unit 3
,
84-01- 84-01 118 Operational safety regarding l
individual rod scramming
activities
84-02 84-02 29 Plant Modification
Activities
84-03' 84-03 268 Operational Safety
84-04 84-04 38 Torus modification
requirements and IE
84-05 84-05 12 Review Eastern Testing
and Inspection, Inc.,
84-06 84-06 36 Security
84-07 84-07 172 Operational Safety
84-08 84-08 112 Previous inspection
findings, corrective and
preventive maintenance,
and document control
84-09 84-09 32 Transportation activities
'
84-11 84-11 33 Enforcement Conference
84-12 65 Review licensee's
preparations relating to
radiation protection for
planned modification to
recirculation and residual
heat removal (RHR) piping
84-13- 28 Recirculating and RHR pipe
replacement
,
- 84-14 84-12 75 QA/QC Program and the
piping replacement program
. - _- ._ -- -
T3-2
Table 3 (continued)
Report Inspection Hours Areas Inspected
Unit 2 Unit 3
84-15' 84-13 233 Operational Safety
84-16 84-14 8 Bioassay whole body
counting program
84-17 84-15 104 Corrective and preventive
maintenance programs
84-18 70 Radiation protection
program ,
84-19 84-10 70 Special Security
Inspection
,
84-20 84-16 147 Operational Safety
'
84-21 84-17 31 Recirculating and RHR
pipe replacement
84-22 593 Operations Assessment Team
Inspection (Outage
assessment)
84-23 84-18 31 Licensing issues on torus /
drywell vacuum breaker and
air sampling system; QA
program implementation
84-24 84-20 149 Operational Safety
.
84-25 84-11 112 Whole body counting
program
84-26 84-22 28 Closing electrical
inspection report
findings
84-27 84-23 Enforcement Conference
84-29 22 Radiation exposure to
three workers
_ - _ _ _ _ _ _ _ _ _ . _ _ . -- . . _ _ _
_ _ .
T3-3
Table 3 (continued)
Report Inspection Hours Areas Inspected
Unit 2 Unit 3
84-30. 84-24 26 Torus modification
requirements and IE Bulletin
78-11; and review of the
licensee's organization and
procedures for performance
and control of major
modifications
-84-31 '84-25 186 Operational Safety
l
84-32 84-26 101 Operational Safety
84-33 84-27 244 Emergency Preparedness
(Annual Exercise)
84-35 84-29 275 Operational Safety
84-38 84-31 36 Inspect licensee's
program for recirculating
and RHR pipe replacement
84-39 84-32 52 Operational Safety
84-40 84-19 34 Fire protection / prevention
program
84-41 84-33 48 Licensee's activities
related to NRC Bulletin
identified items and
surveillance of pipe
supports, restraints and
84-42 84-34 40 Radioactive waste management
i- program
85-01 633 NRC Mobil NDE Van
85-02 85-02 33 Security and Safeguards
- 85-03 85-03 244 Emergency Planning Team
Inspection
m. -
T3-4
Table 3 (continued)
Report Inspection Hours Areas Inspected
^ Unit 2- Unit 3
85-04 85-04 29 Recirculation
safe end repair and
replacement
85-05 85-05 39 ISI/ PSI Activities
85-06 85-06 20 Nonradiological chemical
program
85-07 (3-07 40 Special Inspection
Operational Safety
85-08 85-08 406 Operational Safety
85-09' '85-09 78 Effluent control program
and radiochemical
measurements program using
the NRC:I Mobile
Radiological Measurements
Laboratory
85-10 20 Local Leak Rate Test (LLRT)
Program
85-11 85-11 29.5 Special inspection to review
the contamination of several
workers
85-12 85-12 After SALP period Operational Safety
'
85-13 1.5 Enforcement Conference
85-14 11 Assessments of external
and internal exposures
resulting from events
described in Inspection
50-277/85-11 and the
licensee's corrective
actions as described in
Report 50-277/85-13.
L .- - - .
..
T4-1
TABLE 4
INSPECTION HOURS SUMMARY
PEACH BOTTOM ATOMIC POWER-STATION
UNITS 2 and 3
Functional Area Hours % of Time
1. . Plant Operations........................ 1850 34.0
2. Radiological Controls................... 489 9.0
3. Maintenance............................. 442 8.0
4. Surveillance............................ 170 3.0
5. Fire Protection.......................... 84 1.0
6. Emergency Preparedness.................. 538 10.0
7. Security and Safeguards................. 195 4.0
8. Refueling /0utage Activities............. 1654 31.0
9. Licensing Activities.................... *- ---
T0TAL....................................... 5422 100%
- Hours expended in facility licensing activities are not included with direct
inspection effort statistics.
,
F
t. . _
T5-1
TABLE 5
U(!DLANNEDAUTOMATICSCRAMSANDFORCEDOUTAGES
PEACH BOTTOM ATOMIC POWER STATION
Unplanned Automatic Scrams
Unit Date Power Level (%) Cause
3 2/9/84 100 Power spike resulting from pressure
surge associated with malfunctioning
3 7/11/84 100 APRM high flux scram occurred
following lightning strike on 500 KV
bus tie line
3 8/21/84 100 Low reactor water level caused by
malfunction in feedwater control
circuit
3 11/14/84 20 APRM high flux scram as the B
recirculation pump was restarted
3 3/1/85 25 Low main condenser scram due to loss
of offgas system combined with high
condenser in leakage
Forced Outages
Unit Date Cause
3- 1/14/84 Loss of condensate pumps due to
room flooding
2 1/28/84 RCIC testable check valve
leak
2 2/18/84 MSIV and feedwater check valves
2* 2/27/84 Control rod pattern adjustment
2* 3/2/84 Water box inspection and repair,
and control rod pattern
adjustment
3* 3/16/84 Water box inspection and repair,
and control rod pattern
adjustment
3* 3/20/84 Control rod pattern adjustment
'
'3* 3/23/84 Control rod pattern adjustment
-
T5-2
TABLE 5(continued)
Forced Outages (continued)
Unit- Date Cause
3* -4/20/84 Control rod pattern adjustment
and rondensate pump repair
2 4/28/84 Shutdown for sixth refueling
outage
3 6/2/84 RCIC valve and feedwater
heater repair; and weld
overlay of the jet pump
instrumentation nozzles
3* 9/29/84 Load reduction for control rod
adjustments, B and C circulation
pump work, B and C condensate
pump work
3* 10/25/84 Lead reduced to lower radiation
levels in the off gas
3 11/6/84 Repair valve packing leak in
drywell
3* 11/24/84 Load drop for condenser water
box work
3* 12/1/84 Load reduction for waterbox leak
repair
3* 12/10/84 Load drop to repair recombiner
condenser tubes
3* 12/15/84 Load drop for control rod
adjustment
3* '12/20/84 Load reduction to limit off gas
releases
3* 1/5/85 Load reduction to repair broken
test tap on the 3A condensate
pump
T5-3
TABLE 5(continued)
Forced Outages (continued)
Unit Date Cause
3* 1/15/85 Load drop due to the E4 diesel
and 39A RHR valve inoperability.
The valve was returned to service
prior to unit shutdown.
3 1/23/85 Generator taken off line to clean
up an oil leak which caused a
generator field ground.
3 2/1/85 Mini-outage for surveillance -
testing and miscellaneous
maintenance (main steam isolation
valves and leak testing).
3* 3/9/85 Control rod pattern adjustment
and condenser tube leak repair
- Load drops / reductions only-
-
T6-1
TABLE 6
NRR SUPPORTING DATA AND SUMMARY
A. This following is summary of significant licensing actions and other
activities during the assessment period.
-1. NRR/ Licensee Meetings - 4
IGSCC (Pipe cracks) and pipe repair / replacement
Backup E0F
PECo-H. Thompson meeting
Purge / Vent TS
2. NRR Site or Component Officer Visits - 3
PM Annual Data Visit (1984 and 1985)
Audit of SPDS
Regulatory. Performance meeting
3. Schedules Extensions Granted - 2
Annual Emergency-Exercise
Equipment Qualification
4. Relief Granted - 1
5. Technical Exemptions Granted - 1
Fire Protection
.6. License Amendments Issues - 35
'7 . Emergency Technical Specification Changes Issued - none
!
8. Orders Issued - 1
Confirmatory Orders on NUREG-0737, Supplement 1 (both units)
9. 'NRR/ Licensee Management Conferences - none
.B. .The following details the NRR licensing actions completed during this
assessment period.
o Plant-specific actions (48 completed): Actions in this
category which were used.to provide input for this evaluation.
n -
I
T6-2
Table 6 (continued)
-
' Review of plant specific Appendix R technical exemptions
-
Coolant Leakage Technical Specifications (TSs)
-- Reactor water cleanup and scram discharge volume TSs
- TS on local leak rate testing
- Increased core flow TSs
-
Hydrogen chemistry test TSs
-
Requalification exam extension-
-
Unit 2 reload
o 20 multi plant actions (16 completed): Actions in this
' category which were used to provide input for this evaluation
are:
- Environmental Qualification
-
- Purge / Vent Valve Operability
o 20 NUREG-0737 actions (10 completed): Actions in this
category.which were used to provide input for this' evaluation
are:
- Inadequate Core Cooling Guidelines (I.C.I.2.A)
-
SPDS (I.D.2)
- Post Accident Sampling (II.B.3)
-
Failures of Relief Valves (II.K.3.16)
!
.