ML20202E225
| ML20202E225 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 06/11/1986 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202E214 | List: |
| References | |
| 50-317-84-99, 50-318-84-99, NUDOCS 8607140308 | |
| Download: ML20202E225 (62) | |
See also: IR 05000317/1984099
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SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
INSPECTION REPORT NO. 50-317/84-99; 50-318/84-99
BALTIM0RE GAS AND ELECTRIC COMPANY
CALVERT CLIFFS NUCLEAR POWER PLANT
ASSESSMENT PERIOD: OCTOBER 1, 1984 - APRIL 30, 1986
BOARD MEETING DATE: JUNE 11, 1986
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8607140308 860708
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TABLE OF CONTENTS
PAGE
I. INTRODUCTION......................................................... 1
A. Purpose and 0verview............................................ 1
B. SALP Board Members.............................................. 1
C. Background...................................................... 2
II. CRITERIA............................................................. 5
III. SUMMARY OF RESULTS................................................... 7
A. Facility Performance............................................ 7
B. Ove ral l Faci l i ty Eval uation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
IV. PERFORMANCE ANALYSIS................................................. 9
A. Plant Operations................................................ 9
B. Chemistry and Radiological Control s. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
C. Maintenance..................................................... 16
D. Surveillance.................................................... 20
E. Emergency Preparedness.......................................... 23
F. Security and Safeguards......................................... 25
G. Refueling, Outage Management and Engineering Support............ 27
H. Licensing Activities............................................ 31
,
I. Assurance of Quality............................................ 33
J. Training and Qualification Effectiveness........................ 36
V. SUPPORTING DATA AND SUMMARIES........................................ 39
A. Investigations, Petitions and A11egations....................... 39
B. Escalated Enforcement Actions................................... 39
C. Management Conferences.......................................... 39
D. Licensee Event Reports.......................................... 40
TABLES
- TABLE 1 - INSPECTION REPORT ACTIVITIES
j TABLE 2 - INSPECTION HOUR SUMMARY
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TABLE 3 - VIOLATIONS SUMMARY
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TABLE 4 - LISTING OF LERS BY FUNCTIONAL AREA
TABLE 5 - LER SYN 0PSIS
TABLE 6 - UNPLANNED TRIPS AND OUTAGES
TABLE 7 - SUMMARY OF LICENSING ACTIVITIES
ATTACHMENTS
ATTACHMENT 1 - TIME SHUT DOWN PER MONTH IN DAYS
ATTACHMENT 2 - TOTAL NUMBER OF SHUTDOWNS AND TRIPS PER YEAR SINCE STARTUP
(UNITS 1 AND 2)
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I. INTRODUCTION
A. Purpose and Overview
The Systematic Assessment of Licensee Performance (SALP) is an integrated
NRC staff effort to collect the available observations and data on a
periodic basis and to evaluate licensee performance based upon this in-
formation. 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 operation.
The NRC SALP Board, composed of the staff members listed below, met on
June 11, 1986 to review the collection of performance observations and
data to assess licensee performance in accordance with 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 safety per-
formance at the Calvert Cliffs Nuclear Power Plant for the period October
1, 1984 through April 30, 1986. It is noted that the summary findings
and totals reflect a 19 month assessment period. ,
8. SALP Board Members
Board
R. W. Starostecki, Director, Division of Reactor Projects (DRP) and
Chairman
E. C. Wenzinger, Chief, Reactor Projects Branch 3, DRP
L. Tripp, Chief, Reactor Projects Section 3A, DRP
T. Foley, Senior Resident Inspector, Calvert Cliffs NPP
D. Jaffe, Licensing Project Manager, NRR
A. Thadani, Director, PWR Directorate #8, NRR
W. Johnston, Deputy Director, Division of Reactor Safety
J. Joyner, Chief, Nuclear Materials Safety and Safeguards Branch, Division
of Radiation Safety and Safeguards
Attendees
D. F. Limroth, Project Engineer, DRP
D. C. Trimble, Resident Inspector, Calvert Cliffs NPP
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C. Background
1. Licensee Activities
Unit 1
At the beginning of the period the unit was operating at full power.
On October 2, 1984, the unit was manually tripped due to the reduc-
tion of main circulating water flow caused by an accumulation of
jellyfish on intake structure traveling screens. During plant re-
start, a Reactor _ Coolant System (RCS) over cooling event occurred
which was principally caused by operator error in over feeding steam
generators. RCS pressure dropped to 1775 psig. The unit returned
to power on October 3.
On November 20, 1984, Unit I was again manually tripped due to an
influx of jellyfish on intake screens. Following the trip, an ex-
traction steam line ruptured filling the turbine building with steam
and causing first degree burns to one individual. The unit returned
to power on November.26. On November 29, the unit was shut down
to repair a flex hose on Reactor Coolant Pump #118 pressure sensing
line and a pressurizer sample valve. Power operation resumed on
December 2.
On December 12, the unit was shut down to repair hydraulic system ,
leakage on #11 Main Steam Isolation Valve (MSIV). During the shut
down, #12 MSIV failed to shut completely. MSIV #11 was repaired
and MSIV #7.2 successfully cycled (however cause of original failure
of MSIV #12 was not positively identified). Power operation resumed
on December 26.
On January 16, 1985, Unit 1 was shut down to repair safety injection
tank check valve back leakage problems. During the shut down, the
root cause of previous #12 MSIV problems was identified and cor-
rected. The unit was restarted on January 19. On February 5, Unit
1 tripped on low steam generator level caused by operator error in
opening a wrong breaker which resulted in a loss of main feeder
pumps. Power operation was quickly resumed.
Unit 1 commenced its Cycle 7 refueling outage on April 6. On !iay
14, an interpolar connecting bar in diesel generator #11 broke free
and caused damage to stator windings. That generator was ultimately
replaced and similar bars were' removed from the remaining diesel
generators. The Unit 1 outage was extended to July 30 due to iden-
tification of damaged insulation in the main turbine generator.
During restart, the shaft seal for #11 B RCP failed and the outage
was extended to August 6. Three trips occurred during start up
(high moisture separator reheater level caused by mispositioned
valve, low steam generator trip due to operator error, and a trip
due to improperly adjusted main turbine thrust bearing wear detec-
tor).
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On September 30, and again on October 3, the unit tripped due to
a DC system ground which caused spurious high main feed-water heater.
level indications to the main turbine protection system. Power
operation was resumed and continued until October 9, when a shut
down was initiated to repair a cracked RCP bleed off line. While
on shut down cooling, 500 gallons of RWT water leaked into contain-
ment through the containment spray header due to a incomplete valve
closure. Power operations resumed on October 15.
On January 23, 1986, the unit tripped due to a malfunctioning of
a Reactor Trip Breaker during surveillance testing. It was re-
started on January 24. From March 17-24, the unit was shut down
to repair a degraded RCP seal and a leaking pressurizer relief
valve. Power operation was then continued through the end of the
period.
Unit 2
Unit 2 began the period operating at full power. On October 3,
1984, the reactor tripped on low steam generator water level due
to the loss of #22 main feed water pump (cause of pump trip not
positively identified). buring plant restart, a series of personnel
and equipment problems occurred nearly simultaneously (main steam
safety valve stuck partially open, two control rod drops (same rod),
a turbine bypass valve stuck shut then inadvertently opened, in-
advertent isolation of a atmospheric steam dump valve). Power
operation was resumed on October 4.
The unit was manually tripped on April 25, 1985 following indication
that two shaft seals had failed on a reactor coolant pump (RCP).
The plant was restarted on May 5; however, the reactor tripped on
low RCS flow during power ascent due to a loss of #21 RCP (faulty
relay caused breaker to trip). Power operation resumed on May 7.
The unit was shut down from May 18 to May 22 to inspect and replace
pressurizer spray valve fasteners. On May 23, with the unit at 100%
power, an inadvertent Recirculation Actuation Signal (RAS) occurred
due to technician error. No plant transients were induced.
. On July 24, Unit 2 was shut down to repair steam leaks on a cold
reheat steam line. During this shut down, #21 MSIV failed to fully
close. Troubleshooting and repair activities took until August 5.
The unit began its sixth refueling outage on October 19. During
- the plant startup in early December, RCF #21 A seal became degraded,
- and the outage was extended through December 10, 1985. On December
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12, the unit tripped on low steam generator water level due to the
loss of #21 MFW pump (erroneous control signal). On February 4,
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1986, the unit tripped for no apparent reason. The cause of the
trip was never identified. Power operation resumed on February 5
and continued through the end of the period.
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2. Inspection Activities
Two NRC resident inspectors were assigned during the inspection
period. The total NRC inspection effort for the period was 5258
hours (resident and region based) or an average of 3312 hours0.0383 days <br />0.92 hours <br />0.00548 weeks <br />0.00126 months <br /> per
year with a distribution in the appraisal functional areas as shown
in Table 2 (Inspection Hour Summary).
During the period, NRC team inspections were conducted of the fol-
lowing areas:
a. Actions taken relative to IE Bulletins 79-02, 79-04, 79-07,
and 79-14.
b. Equipment Qualification (2 inspections).
c. Special inspection of equipment and activities identified in
"Calvert Cliffs Probabilistic Risk Assessment Dominant Se-
quences" as important to prevent or mitigate severe accidents.
d. NUREG 0737 item implementation (Post Accident Sampling System,
Containment Radiation Monitors, Noble Gas Effluent Monitor,
and In Plant Radio-Iodine Measurements).
e. A team inspection of Post Accident Sampling System.
f. Operator Requalification Program.
g. IE Bulletin 80-11, Masonry Wall Design.
An NRC Emergency Preparedness inspection team observed the annual
emergency exercise on September 10, 1985.
Tabulations of Inspection Activities and Violations are attached
as Tables 1 and 3, respectively.
This report also discusses " Training and Qualification Effectiveness"
and " Assurance of Quality" as separate functional areas. Although
these topics, in themselves, are assessed in the other functional
areas through their use as criteria, the two areas provide a synopsis.
For example, quality assura,ce effectiveness has been assessed on
a day-to-day basis by resident inspectors and as an integral aspect
of specialist inspections. Although quality work is the responsi- l
bility of every employee, one of the management tools to measure
this effectiveness is reliance on quality assurance inspections and
audits. Other major factors that influence quality, such as involve-
ment of first-line supervision, safety committees, and work atti-
tudes, are discussed in each area.
The topic of fire protection is not discussed as a separate func-
tional area because of insufficient inspection activity. The avail-
able observations on fire protection and housekeeping are included
in the various relevant functional areas.
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II. CRITERIA
Licensee performance is assessed in selected functional areas. Each functional
area represents areas significant to nuclear safety and the environment, and
are normal programmatic areas. The following evaluation criteria were used
to assess each area.
1. Management involvement and control 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 reportable events.
6. Staffing (including management).
7. Training effectiveness and qualification.
However, the SALP Board is not limited to these criteria and others may have
been used where appropriate.
Based upon the SALP Board assessment each functional area evaluated is clas-
sified into one of three performance categories. The definitions of these
performance categories are:
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 is being achieved.
Category 2: NRC attention should be maintained at normal levels. Licensee
management attention and involvement are evident and concerned with nuclear
safety; licensee resources are adequate and reasonably effective such that
satisfactory performance with respect to operational safety is being achieved.
Category 3: Both NRC and licensee attention should be increased. Licensee
management attention or involvement is acceptable and considers nuclear safety,
but weaknesses are evident; licensee resources appear strained or not effec-
tively used such that minimally satisfactory performance with respect to
operational safety is being achieved.
The SALP Board also assessed each functional area to compare the licensee's
performance during the last quarter of the assessment period to that during
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the entire period in order to determine the recent trend for each functional
area. The trend categories used by the SALP Board are as follows:
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Improving: Licensee performance has generally improved over the last quarter
of the current SALP assessment period.
Consistent: Licensee performance has remained essentially constant over the
last quarter of the current SALP assessment period.
Declining: Licensee performance has generally declined over the last quarter
of the current SALP assessment period.
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III. SUMMARY OF RESULTS
A. Facility Performance
Category Category
Last Period This Period
(10/1/83- (10/1/84- Recent
Functional Area 9/30/84) 4/30/86) Trend *
A. Plant Operations 1 2 Consistent
B. Chemistry and Radiological Controls 1 1 Consistent
C. Maintenance 2 2 Consistent
D. Surveillance 2 1 Consistent
E. Emergency Preparedness 1 1 No Basis
F. Security and Safeguards 1 1 Consistent
G. Refueling, Outage Management and
Engineering Support 1 2 No Basis
H. Licensing Activities 1 1 Consistent
I. Assurance of Quality N/A 2 No Basis
J. Training and Qualification
Effectiveness N/A 2 Consistent
- Trend during the last quarter of the assessment period.
B. Overall Facility Evaluation
The recent organization has had significant positive impact by providing
increased management attention in all areas. Management support and
resources are made available to correct recognized problems in a timely
fashion. Numerous management programs continue to demonstrate the lic-
ensee's pursuit of quality, regulatory compliance, and efficient opera-
tions. Programmatic weaknesses were noted in the timeliness in which
potential safety issues are recognized, lack of effectiveness in solving
recurring problems in the Instrumentation and Controls area with a re-
sultant effect on reactor operator performance, and the inadequate or-
chestration of multi-discipline tasks in that responsibility and author-
ity are not vested in individuals in such a manner to ensure effective
task completion.
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In several instances, the licensee was slow to recognize the existence
of potential safety issues. Extensive NRC involvement was required be-
fore thorough licensee actions were taken. In other instances, an ex-
cessive number of similar events occurred (e.g., reactor trips) before
thorough licensae investigation, evaluation, and resolution of root
cause(s). POSRC effectiveness was not demonstrated in that root cause
identification rad adequate problem resolution was not always required
for POSRC concurrence. NRC often felt the need to question proposed ac-
tions, suggest additional actions, and generally become directly involved
in a manner normally expected of licensee management and POSRC to achieve
adequate resolution of potential safety issues.
A number of reactor trips and forced outages occurred in both units due
to causes that appeared to be maintenance and design related. Other
trips were due to personnel errors or were precautionary in nature as
a result of maintenance / design related problems. Most trips due to such
causes should be avoidable; however, the licensee had little success in
reducing the frequency of such trips on either unit during the entire
SALP period.
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IV. PERFORMANCE ANALYSIS
A. Plant Operations (1295 hours0.015 days <br />0.36 hours <br />0.00214 weeks <br />4.927475e-4 months <br />, 24.6%)
1. Analysis
The previous SALP determined the operations area to be Category 1.
It concluded that additional management emphasis was needed to
(1) properly evaluate temporary changes (pursuant to 10 CFR 50.59)
! to the facility prior to implementation and (2) improve the effec-
4 tiveness of the Plant Operations and Safety Review Committee (POSRC).
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That committee had been slow to recognize the potential safety sig-
i nificance of major salt water system corrosion problems. 10 CFR
- 50.59 evaluations have improved. However, although attempts have
been made to improve POSRC effectiveness, significant problems con-
tinue to exist. Untimely recognition of potential safety issues
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and inadequate analysis for the identification and resolution of
root causes of plant trips, ESF actuations, and other safety related
i problems persist. Inadequate root cause analysis was demonstrated
] by recurring Main Steam Isolation Valve (MSIV) inoperability prob-
lems becuase of failure to identify the root cause after the first
- event (see Maintenance functional area). Additionally, repeating
i plant trips resulted from feed pump control and feedwater heater
level circuit problems. Again, root cause analysis was deficient
after the initial and often after the second event (see Table 6 for
] trips occurring on 10/3/84, 9/30/85, 10/2/85, 12/12/85, and 2/4/86).
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An excessive number of events often have occurred before the licen-
! see will dedicate sufficient time and resources to identify the root
4 cause.
, NRC involvement was necessary to heighten licensee awareness of
! potential safety concerns to a point where corrective action was
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initiated or, where necessary, accelerated. While some instances
of this are to be expected, the relatively large number of occur-
rences during this SALP period indicates that a weakness exists in
the licensee's process of screening for potential safety questions.
Specifically, NRC involvement was necessary to: (1) obtain in-cubicle
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testing of reactor trip breakers; (2) conduct further troubleshoot-
i ing of a main steam isolation valve; (3) conduct further trouble-
shooting of main steam safety valves; (4) adequately evaluate ef-
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fects of a possible cavity seal failure; (5) adequately evaluate
, the use of belzona in repairing salt water system piping; and
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(6) initiate improvements within the Emergency Diesel Generator
rooms. Notwithstanding this weakness, it should be pointed out that
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almost without exception, once the licensee fully recognizes the
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existence of a potential safety problem, they ensure that the root
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cause is identified and thoroughly resolved. An example of this
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was the troubleshooting and repair of a second main steam isolation
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valve. Plant management elected to maintain the plant shutdown to
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l continue troubleshooting (based upon unusual response characteris-
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tics) even though some evidence existed that the valve might be
considered operable.
! During the 19 month period, three reactor trips (2/1/85, 8/6/85,
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and 8/8/85) were attributable to operator performance; operating
j the wrong IAC circuit breaker (Instrument AC instead of Instrument
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Air Compressor) resulted in a turbine / reactor trip, feilure to com-
i ply with the tagout control procedure resulted in a mispositioned
- valve and a turbine / reactor trip, and operator error in maintaining
! steam generator water level with a positive reactivity temperature
- coefficient. One SGIS actuation was caused by operators failing
i to block the signal in accordance with procedure during cooldown.
Operators acted promptly and effectively to avoid several plant
i trips due to malfunctioning air compressor components, and acted
- prudently in initiating precautionary plant trips on 4/25/85 and
j 10/2 and 11/20/84 due to indication of a reactor coolant pump seal
- failure, and severe aquatic fouling of intake structure screens.
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Some weakness was noted in the extent of control room operator
l knowledge of ongoing maintenance activities, including the potential
j impact those activities might have on plant operation. Additional
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weaknesses were noted in the interfaces between the operations and
chemistry groups (e.g., containment isolation sample valves left
i open and sample sink left in recirculation mode without operator
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knowledge) and between the chemistry and licensing groups (e.g. who
i failed to communicate information on what constituted the primary
I and backup post accident sampling systems and failed to ensure the
! chemistry group was aware of a new surveillance requirement for the
- noble gas monitoring system).
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j Two losses of shutdown cooling occurred due to inadequate main-
j tenance/ test procedures. A recent AE00 report pointed out that the
j licensee has had a significant history of losses of shutdown cooling.
j A growing number of problems with control board indications (i.e.,
j approximately 75 MRs per unit) hinder the plant operators' ability
j to monitor _and react to plant conditions.
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The licensee placed strong emphasis on prior planning. Division
and department goals / objectives were clearly stated and widely dis-
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seminated in the form of a " Nuclear Energy Program Plan." They were
j directed toward improved performance versus maintaining status quo
! and addressed the areas of public safety, personnel safety, eco-
i nomic performance, productivity enhancement, and external perception.
{ An Integrated Management System (IMS) has been implemented which
j provides a systematic method for prioritizing plant betterment and
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regulator identified projects by development of benefit to cost
- ratios. IMS is intended to provide a meaningful basis for negoti-
! ating implementation schedules with the NRC and a means for managing
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an integrated work plan for the site. It is closely coupled to the
- - Nuclear Energy Program Plan.
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Fire Protection, personnel safety, and housekeeping continued to
receive strong emphasis. With few exceptions, housekeeping was
excellent, and contamination control was good. The diesel genera-
tors, formerly a problem area due to significant accumulations of
oil and grease on and under the engines, underwent upgrades to cor-
rect sources of oil leakage and were cleaned and painted.
The operations group took a lead role throughout this period in the
area of coordinating maintenance and operations activities. They
helped set maintenance priorities, optimize scheduling, tag equip-
ment out of service at the proper time, and ensured post maintenance
testing was accomplished. They improved their guidance on what
specific post maintenance tests were required for various types of
maintenance.
On January 1, 1986, major organizational changes were implemented
which allowed full involvement of upper level company management
in nuclear activities. Nuclear activities were separated from fos-
sil and gas departments and placed under the direction of a vice
president dedicated to nuclear operations. Three additional manager
level positions were created on site. As part of the company re-
organization, QC functions which had been previously assigned to
the QA department were transferred to line departments. This was
done to provide line supervisors with a tool to ensure work was
being accomplished correctly under the philosophy that quality is
a line function (see Assurance of Quality Functional Area). This
action brought a compliment of QC personnel to the operations de-
partment. Due to the timing of these recent changes, it has not
been possible to evaluate their effectiveness.
Staffing and training levels within the operations group were ex-
cellent. The licensee continued to display a strong commitment
toward licensed operator training as evident by a high success rate
in passing NRC Reactor Operator (RO) and Senior Reactor Operator
(SRO) examinations. Annual written requalification examinations
were administered to 29 SR0s and 25 R0s in which 1 SR0 and 1 RO
failed, who were subsequently re-examined successfully. Three NRC
administered examinations were successfully passed upgrading R0
licenses to SR0 licenses. A Training Effectiveness Inspection was
conducted pursuant to Regulatory Guide 1021 in which 2 SR0s and 4
R0s of one shift crew received NRC written and oral examinations;
3 SR0s and 2 R0 operations staff workers received just an oral ex-
amination and another 3 SR0s and 2 R0 staff workers received'a
written examination. Two individuals failed the written examination,
but were subsequently re-examined successfully. No generic weak-
nesses were noted during the inspection. The licensee maintained
69 current licenses, 38 SR0s and 31 R0s. Discussions with licensed
operators indicated that the training staff was responsive to their
input, and that training improved in quality with the advent of new
site specific simulator in January 1986. Formally, the simulator
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began operation in September 1985 with symptom based Emergency
Operating Procedure training. Simulator training was preceded by
meetings between the operations crew shift supervisor and the simu-
lator instructor. This provided operations input and tailored each
class to specific perceived weaknesses as well as the requisite
training.
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The operations training program had an in progress task analysis
- to define the specific skills of the operator. This job task an-
alysis was being combined with INP0's requirements and NRC's KSA
Catalog (Knowledge, Skill, and Abilities).
, In summary, the Operations Department provided excellent prior main-
tenance planning and logical assignment of priorities. Conservatism
was routinely exhibited after a potential safety issue was recog-
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nized. There were few long standing regulatory issues. Weaknesses
were noted in operator awareness and possible effects of ongoing
plant maintenance and personnel errors contributing to reactor
trips, ESF actuations and losses of shut down cooling. A signifi-
cant weakness was noted in the apparent reluctance to perform a
thorough diagnostic assessment for true root cause of events in a
timely fashion and excessive reliance on NRC involvement before
potential safety issues were recognized and adequately pursued.
2. Conclusion
Rating: Category 2.
l Trend: Consistent.
3. Board Recommendation
Licensee
Increase management attention to more aggressively recognize poten-
tial safety issues and to improve the root cause analysis of prob-
, lems.
NRC
None.
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8. Chemistry and Radiological Controls (901 hours0.0104 days <br />0.25 hours <br />0.00149 weeks <br />3.428305e-4 months <br />, 17%)
1. Analysis
There were fourteen inspections conducted by radiation specialists
during this period. The inspections examined the licensee's radi-
ation protection program, radioactive waste management and effluent
- controls, environmental monitoring program, and transportation of
radioactive material. A team inspection of Post Accident Sampling
Systems and a non-radiological chemistry program review were also
performed. Resident inspectors monitored the implementation of the
radiation protection programs, as well. There were four Licensee
Event Reports (LERs) in the Radiological Controls area during this
assessment, the same number as in the previous assessment period.
However, they were not repetitious.
The radiological protection program was well staffed with highly
,
qualified and trained personnel. Particular program strength was
evidenced by the high quality performance of the radiological con-
trols staff in several program areas, including the ALARA program,
and controls during the conduct of high exposure operations.
Facilities and equipment were well maintained with excellent per-
formance records, including the new material processing facility.
This new facility provided for well controlled and timely mainten-
ance, testing and inspection of respirator protection equipment.
This contributed to a high quality respirator protection program.
Due to fully qualified staff and well designed facilities, a strong
program for handling, storage, and segregation of radioactive waste
l was in place. The equipment, facilities, and operations of the
whole body counting facilities were particularly impressive. Using
these facilities, the licensee measurements of the NRC provided
phantom were in full agreement with the type and quantities of
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isotopes in the phantom.
The ALARA program was strong and effective with good management
support. ALARA reviews of planned work was thorough and revaluation
of work in progress was excellent. During the course of several
inspections in this rating period, the ALARA program was examined
and found to be commendable.
l The licensee's ALARA person-rem goal for the site was 720 for 1985.
The total exposure for 1985 was 648 person-rem. During 1985 signi-
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ficant radiological operations occurred including two refueling
outages. An aggressive ALARA person-rem goal (upper limit) for 1986
. was established at 391 person-rem for the site. By the end of this
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assessment period, only 13% of the limit had been experienced. This
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was due to the licensee's management commitment to effectively re-
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duce radiation exposure,
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The external and internal exposure control programs were well
founded and technically sound. These programs were supported by
clearly defined policies and procedures. However, non recurrent
violations were identified by NRC including failure to follow pro-
cedures, exposure records keeping, and lack of a detailed procedure
for the standup whole body counter. These were infrequent minor
problems and not indicative of any substantial program weakness.
The radiation controls Quality Assurance audits were performed in
a timely and comprehensive manner. Correction of audit findings
was timely and technically sound.
The licensee implemented an effective radioactive waste management
program. Licensee personnel at all levels in the radwaste opera-
tions were very knowledgeable with regard to their functions and
responsibilities. No problems were identified. On going training
was evident.
Based on an inspection conducted October 1985, the licensee did not
have a program that included implementing procedures for identifying,
sampling, and analyzing the various waste streams to assure compli-
ance with 10 CFR 61, even though a program was required after
December 27, 1983.
The licensee performed periodic audits of the transportation program.
The audits were performed in accordance with the requirements of
Part 50, Appendix B. However, the frequency of auditing criteria
applicable to transportation of radioactive waste was not specific-
ally established.
The licensee had adequate chemistry and radiochemistry programs.
The licensee met Technical Specification requirements for in plant
and effluent sampling and analysis, and, in particular, the licensee
met their new Radiological Effluent Technical Specifications (RETS),
which were implemented on July 1, 1985. Review of the licensee's
implementation of the RETS noted a lack of thoroughness in some
areas. For example, surveillance procedures had not been formalized
for monitor calibration, training was not well documented and records
of procedure change for the liquid discharges were not available.
During the assessment period, an inspection was conducted using the
NRC I Mobile Radiological Measurements Laboratory. All in plant
and effluent samples split between the licensee and the NRC during
this inspection were in agreement. Minor follow up items were
identified during this inspection that indicate a lack of initiative
by the licensee to make constant improvements in the program in
order to maintain and improve the quality of the analytical meas-
urements. These items included the quality control of radiochemical
measurements including lack of participation in any interlaboratory
comparions, use of control charts, and other control statistics.
.
h
15
Weaknesses identified in the non-radiological chemistry program were
eliminated and toward the end of the SALP period, significant im-
provements in the controls of analytical measurements were achieved.
NRC inspections identified significant deficiencies in the Post Ac-
cident Sampling System (PASS). A failure of the on site chemistry
group to assign sufficient priority to the operation of PASS led
to a number of these deficiencies (e.g. Inadequale procedures and
system dilution factors not determined). However, causal factors
external to the chemistry group were also involved. PASS problems
are therefore more fully addressed in the Refueling Functional Area
of this report.
In summary, only minor problems were identified regarding personnel
exposure controls and technical specification surveillances for
plant ventilation systems.
2. Conclusion
Rating: Category 1.
Trend: Consistent.
3. Board Recommendation
Licensee
None.
NRC
None.
.
%
16
C. Maintenance (837 hours0.00969 days <br />0.233 hours <br />0.00138 weeks <br />3.184785e-4 months <br />, 16%)
1. Analysis
The previous SALP identified problems with (1) recurring equipment
deficiencies, (2) insufficiently aggressive program to assess and
correct salt water system corrosion problems, (3) and weak post
modification follow up (insufficient controls for ensuring oper-
ability and priority for repair as well as lack of support by the
the installing organization) for TMI action plan items. Addition-
ally, a concern was raised whether equipment qualification was being
adequately considered in the maintenance program. A summary of
licensee performance in these areas is described below.
Resolution has been achieved on most of the material problems noted
in the last SALP report. Problems with charging pump packing leak-
age and SGFW pump control continued. Charging pump packing was a
concern because tt.e licensee recently took credit for these pumps
in their safety analysis. Barton pressurizer pressure transmitter
drift problems were still occurring, but at a reduced rate. Barton
had not provided an acceptable resolution, and the licensee was
asking another vendor to develop and provide a substitute transmit-
ter. During the interim, Barton transmitter performance was rou-
tinely monitored to detect drift.
A large program was ongoing regarding salt water system corrosion
problems. The thorough corrective action program for components
susceptible to graphitic corrosion was on track. A number of those
components had been replaced (e.g., component and service water' heat
exchanger channel heads), and plans were underway to replace others
(e.g., salt water pump casings). Improved inside wall coatings and
cathodic protection were being used. A general problem still ex-
isted with wall thinning and periodic occurrence of small, through-
wall holes in carbon steel piping, where the cement-mortar protec-
tive lining had eroded or broken away. This leaves the bare metal
directly exposed to the corrosive effects of saltwater. A program
was ongoing to replace piping in high turbulent flow areas with
rubber lined pipe.
NRC inspections during the period disclosed significant deficiencies
in the installed Post Accident Sampling System (PASS). These de-
ficiencies are described and included in this assessment in the Re-
fueling Outage Management functional Area of this report. Finally,
during the period, a program to include equipment qualification re-
quirements in maintenance activities was implemented. Further de-
tails on licensee performance in equipment qualification areas is
also provided in the Refueling and Outage Management Functional Area
where its impact on this assessment is considered.
.
b
17
The recent company reorganization described in the operations sec-
tion brought increased management attention to the maintenance area.
As a result of an in depth review of the maintenance program, major
changes and enhancements of existing programs were being initiated:
1. Implementation of the systems engineer concept.
2. Creation of a centralized planning and scheduling group that
provided improved coordination within the maintenance depart-
ment and with the Operations Department.
3. Improvements in training programs.
4. Joint effort with the Electric Power Research Institute (EPRI)
to upgrade design and performance of valve packing.
5. Establishment of a " roving" maintenance crew on the back shift
to support post maintenance testing and to conduct minor main-
tenance activities. This program has proven effective in
reducing the number of outstanding maintenance requests.
The licensee made major changes in the Quality Control (QC) area.
Maintenance QC functions were transferred to the Maintenance De-
partment. An enhanced cross training program was initiated to im-
prove QC inspectors knowledge and skills and maintenance personnel's
knowledge of the quality control philosophy.
Notwithstanding the above, the following problems were identified:
1. During the period, weaknesses were noted by the NRC in the
qualification program for maintenance personnel assigned re-
sponsibility for Reactor Coolant Pump (RCP) seal rebuildir;.
This coupled with seal performance problems in service cr.Jsed
the licensee to organize a RCP shaft seal task force to review
seal performance, training of maintenance personnel, quality
of spare parts, operating practices, and maintenance procedures.
2. Problems were noted in the area of maintenance procedures.
Two losses of shutdown cooling events resulted from inadequate
procedures by the Instrument and Control Department. The lic-
ensee exercised the option of omitting detailed steps from
procedures when the task was considered within the knowledge,
skills, and abilities of the worker. Additionally, certain
temporary modifications (lifted wire / temporary jumpers) were
exempted from screening for unreviewed safety questions when
accomplished and restored within one shift. In combination,
the option of omitting detailed steps in maintenance procedures
and the exclusion of reviews of certain temporary changes has
... - -
.
5
18
led to abuse and allowed work on safety related systems without
adequate screening for possible effects. Procedure writing
groups were appointed and were rewriting / revising procedures.
More than two hundred maintenance related procedures were
improved through such efforts during this assessment period.
3. Following an incident where pressurizer spray valve fasteners
failed due, in part, to over torquing, the licensee embarked
on an extensive program to improve training and controls over
fastener torquing.
4. Problems due to main feedwater pump speed control circuity
possibly due to electrical grounds and/or component failures
led to two plant trips during the SALP period and two addi-
tional trips immediately following the period. Electrical
grounds on feedwater heater level control circuity caused two
automatic plant trips. Additional maintenance problems led
to u.nplanned trips and outages and included: safety injection
tank check valve leakage, a main steam isolation valve hydraulic
oil system leak, and an improperly adjusted thrust bearing wear
detector. The cause of one trip late in the SALP period was
unidentified but may also have been due to an electrical ground
problem. The licensee willingness to " live with" ground prob-
lems prompted trore active NRC involvement to effect problem
resolution.
Although the corrective maintenance backlog was relatively low at
600 Maintenance Requests (MRs) or 5 man weeks, numerous MRs accumu-
lated on each unit's control board (75 on each). Each MR was
evaluated with respect to its effect on the system. However, no
evaluation was done on the total effect of the sum, nor was a limit
established before a concerted effort was devoted to reducing the
shear volume of MRs/ problems with the control boards. Most of these
MRs were related to the I&C Department. Further, several plant
trips were apparently caused by poor maintenance (see Table 6).
Several trips were repetitive due to a lack of thorough understand-
ing of the control systems (see trips dated October 3, 1984, Sep-
tember 30, 1985, and December 12, 1985). Together, the backlog of
I&C related MRs on the control boards and related plant trips with-
out sufficient control eystems expertise indicates a weakness in
this segment of maintenance, and contributes to confusion and im-
paired performance by the reactor operators.
Despite the licensee's efforts to miniraize rework and to identify
root causes of problems, their approach to the resolution of prob-
lems differed with each occurrence. There was no pre planned
standard approach that was well laid out, nor any set group of per-
sonnel that had experience in problem solving. Troubleshooting
efforts appeared to be overly limited to the perceived most likely
.
m
19
causes to the exclusion of others. Because of this the approach
to resolution of several technical issues was less than thorough
and progressed at times in an impulsive fashion.
The licensee has the capability to thoroughly evaluate and satis-
factorily resolve problems once they are focused and committed.
The plant nuclear engineering group (part of the maintenance de-
partment) worked very effectively with the General Supervisor
Operations in resolving three equipment problems (two main isolation
valve issues and main steam safety valve setpoint drift problems).
In summary, several of the material problems identified in the pre-
vious SALP have been corrected. Continued effort is still required
to fully resolve main feed water control, salt water system corro-
sion, charging pump packing, Barton transmitter, reactor coolant
pump seal, and steam piping erosion / movement / support problems. The l
reorganization strengthened the Maintenance Department by placing
a manager on site who was the previous plant superintendent. In-
creased resources were being devoted to this area. The establish-
ment of the systems engineer concept and other innovations have the
potential for improved performance in this area. Major changes were
already evident, i.e., diesel generator up keep, condensate area
clean up, and roving maintenance crew reduction of maintenance
backlog. Procedure development and training programs resulting from
task analyses were in progress. Additional I&C engineering support
is needed because of weaknesses in the staffing, direct line super-
vision, vendor support, and spare parts areas. Increased screening
of maintenance activities for possible unreviewed safety questions
is needed.
2. Conclusion
Rating: Category 2.
Trend: Consistent.
3. Board Recommendation
Licensee:
Evaluate impact of secondary system maintenance problems on reactor
trips (frequency, cause). Determine if poor maintenance and/or de-
sign weaknesses are contributing to balance of plant related trips.
NRC:
Conduct meeting with licensee to discuss their trip reduction pro-
gram ef forts.
,
9
.
b
20
D. Surveillance (885 hours0.0102 days <br />0.246 hours <br />0.00146 weeks <br />3.367425e-4 months <br />, 16.8%)
1. Analysis
The resident inspectors examined surveillance activities as part
of the routine inspection program. Surveillance procedures related
to specialized areas of inspection were reviewed during thirteen
inspections conducted by region based personnel.
The previous SALP noted that NRC inspections had identified a sig-
nificantly high number of administrative and technical deficiencies
in surveillance test procedures (STP's). An in depth QA auditing
effort was conducted by the licensee to correct problems of this
nature by ensuring that (1) STP's adequately accomplish all Techni-
cal Specification surveillance requirements, (2) systems are pro-
perly restored to proper alignment following STP's, and (3) sur-
veillance tests are properly documented. There were two instances
of deficient procedures during this period. One led to an initi-
ation of an Engineered Safety Features Actuation system. A second
resulted in missed survelliance tests on two control room ventila-
tion dampers. The reduced rate of occurrence indicates that the
quality of test procedures as a whole has improved. The control
room damper problem was recurrent from the last SALP period indi-
cating that initial corrective actions for that system were not
sufficient to recognize remaining deficiencies.
The number of missed / late surveillance tests was reduced from a
total of four last SALP period to one during this period.
NRC inspections covered a broad cross section of surveillance acti-
vities. In general, procedures were found to be clear and techni-
cally sufficient; and testing was accomplished in accordance with
procedures by appropriately qualified personnel. Workers performing
those tests appeared knowledgeable of the systems and testing re-
quirements. QC/QA involvement was evident. Surveillance activities
for the following areas were included within the scope of these in-
spections: plant mechanical and electrical systems, containment leak
rate testing, in service inspections, environmental monitoring,
radioactive effluent monitors, refueling, snubber program, control
room habitability, ventilation filter testing, and chemistry samp-
ling.
The licensee continued the practice of conservatively entering
Technical Specification action statements when equipment was under-
going surveillance tests. This assured operator awareness of plant
status and discouraged maintenance on redundant trains that could
cause degraded conditions.
. -
,
g n*
4
21
Management planning was evident in the area of In Service Inspec-
_ tions (ISI). A majority of the system ten year hydrostatic tests
requirements were completed in advance of the upcoming ten year ISI
refueling outages.
'
'
The licensee conducts surveillance programs which go beyond minimum
Technical Specification requirements relative to steam generator
(SG) integrity and primary chemistry. They took an active role in
industry efforts'in these areas. A steam generator task force was
organized by the licensee to monitor eddy current testing, chemistry
hide'out, condenser air in leakage, steam generator lay up condi-
-tions, sludge-lancing, and abnormal chemistry trends. During out-
ages the' licensee consistently performed eddy current testing on
more than the minimum number of SG tubes required by Technical
Specifications.
The recent company reorganization necessitated changes in surveil-
lance program responsibilities. A weakness was noted in that a plan
for reassignment of surveillance responsibilities was not developed
prior to the reorganization. At the close of the SALP period, the
surveillance program continued to function under the previously as-
signed coordination staff.
An unplanned outage was caused by pinhole steam leaks in a turbine
cold reheat steam line. Two inadvertent Engineered Safety Features
^
System actuations were caused as a result of surveillance activities
(one due to personnel error and one due to inadequate procedure).
The-licensee has experienced a significant problem with an increas-
ing trend of low pressure steam line leaks / ruptures. These leaks
have been apparently due to erosion of carbon steel pipe due to
moisture saturated / low pressure steam. Although the licensee has
-
devoted considerable effort toward prioritizing and conducting sur-
veillance of pipe wall thickness and replacing thinned piping, the
problem is not resolved and is possibly expanding. Many areas of
piping have ~not yet been inspected and leaks continue to occur.
A more aggressive program is needed to stay ahead of the problem.
In summary, procedures appear well stated, clear, conservative and
rarely violated. The numbers of inadequacies were significantly
reduced from the previous assessment period. Licensee policies
required conservatism in entering and interpreting Technical Spect-
fications. The surveillance program was effectively managed. A
significant problem exists with erosion of steam piping.
~
2. Conclusion
Rating: Category 1.
,
f Trend: Consistent.
o
_.
.
22
3. Board Recomendation
Licensee:
A baseline survey of wall thickness of pipe susceptible to erosion
should be conducted on a high priority basis.
NRC:
None.
w
s- <
b
i
!
t.
i
l
l
l
!
l
l
, . . - - -, . . . - - . . , , , , - , , , - - , _ , - - - . - - - - , _ . - - . - - - - . . . _ , . - - - - . , - - _ . - , . - . . . , - - - - - . - - . _ _ ~
.
.
23
E. Emergency Preparedness (211 hours0.00244 days <br />0.0586 hours <br />3.488757e-4 weeks <br />8.02855e-5 months <br />, 4%)
1. Analysis
During the assessment period, there were two routine inspections.
One inspection was observation of the full-scale emergency pre-
paredness exercise on September 10, 1985. There were no violations
or reportable events noted during the assessment period which re-
lated to the licensee's state of emergency preparedness.
Overall, the licensee has been responsive to most NRC initiatives
and the findings indicate an acceptable level of performance in
emergency preparedness. The emergency preparedness program was
being maintained at its current state. Staffing and support for
the program both at the site and from the corporate office were also
maintained. Actions taken towards continued improvement consisted
of:
(a) Establishment of a Dose Assessment computer surveillance pro-
gram to improve system availability and reliability.
(b) A Quality Assurance program verifying validity of plant
meteorological data.
(c) The Dose Assessment program (MIDAS) was changed to include an
integrated dose calculation capability (allows totalizing sec-
tor doses in 15 minute intervals to enhance offsite dose cal-
culations).
(d) An automatic telephone ring down circuit was installed in the
control room to connect all applicable emergency centers.
(e) The onsite simulator now validates the drill scenario data.
Other program improvements are in progress or being sought, however,
are not yet implemented.
Training deficiencies, however, were noted in that not all personnel
had participated in the 1985 annual training program. A repetitive
finding noted that the Radiological Assessment Director (RAD) in-
adequately assessed the use of potassium iodide.
,
In the area of dose assessment, the post-TMI action items III.A.22
on representative meteorological monitoring and refined dose calcu-
lations were still awaiting action. Coastal nuclear power plant
sites need to address the complexity of wind flow patterns in the
vicinity of the site. The MIDAS system (a family of computer codes
for data acquisitions and dose assessment) was only used as a backup
to both the manual dose calculations and verbal meteorological
transfe'r of data to the EOF in the last emergency preparedness ex-
.
.
24
ercise. The licensee has recently installed the system in the Con-
trol Rooms, the TSC, and E0F to improve reliability and familiarity
with the system.
These concerns were discussed with the licensee during the September
10, 1985 exercise, and were highlighted by the licensee in its
self-critique, which was quite thorough. The licensee's performance
during this exercise demonstrated their capability to protect public
health and safety within the constraints of the scenario.
During the period, the inspector met with local officials who indi-
cated favorable working relationships with the utility. Adequate
resources and routine training to county emergency preparedness
personnel were provided.
2. Conclusion
Rating: Category 1.
Trend: No basis.
3. Board Recommendaticn
Licensee
None.
NRC
None.
l
,
L
l
1
i
,
I
,
- - ,
..
.
.
25
F. Security and Safeguards (288 hours0.00333 days <br />0.08 hours <br />4.761905e-4 weeks <br />1.09584e-4 months <br />, 5.5%)
1. Analysis
During the previous SALP period, the licensee's performance in this
area was Category 1. No major issues were identified.
During this assessment period, three unannounced physical protection
inspections were performed by regional based inspectors. Routine
resident inspections continued throughout the assessment period.
Interviews of security force members and observations of program
implementation during inspections throughout the assessment period
indicated the licensee's commitment to implement a high quality
security program and to maintain an effective security organization.
This was evident by the licensee's continuing attention to program
needs, prompt implementation of program enhancements, maintenance
of an excellent training program, and interaction with other utili-
ties regarding security matters.
Both plant and corporate management continue to exhibit a strong
influence on the security program at Calvert Cliffs and in nuclear
power industry plant security in general. This is demonstrated by
the licensee's planning and budgeting for the gradual upgrading
and/or replacement of security program related equipment by 1989.
Additio1 ally, key security management personnel are actively in-
volved in the Region I Nuclear Security Association and other groups
engaged in innovations in the nuclear plant security area.
The security staff supervisors were well trained, exhibited a pro-
fessional demeanor and continued to provide effective supervision
over other security force members. Other security force members
were observed to perform their assigned duties in a professional,
competent manner. Interviews with security force members revealed
that they were encouraged to recommend improvements in the program
matters they identified while carrying out their routine security
duties.
The training department continued to provide dedicated instructors
for security training and excellent support to the security organi-
zation. As part of security force training, the inspectors observed
the licensee conduct very disciplined and professionally organized
tactical contingency drills. Security force performance during
drills demonstrated the effectiveness of this training and was fur-
ther demonstration of the licensee's attention to the program and
its commitment to quality.
.
.
26
During this assessment period, regional based inspectors advised
licensee security management of generic findings as a result of
Regulatory Effectiveness Reviews (RERs) conducted at other nuclear
power plants. The licensee, on its own initiative, promptly imple-
mented several enhancements to improve the effectiveness of its
program. An RER was subsequently conducted at Calvert Cliffs during
the assessment period. The results of that review indicated that
the licensee's program met NRC security objectives. On matters
identified during the RER which would provide easily achievable
program enhancements, the licensee initiated prompt action. Other
matters were promptly addressed and improvements were being consi-
dered even though the licensee had not received the RER team's re-
port.
Three security event reports were submitted in accordance with the
requirements of 10 CFR 73.71. Two involved isolated cases of per-
sonnel error, and the third was not specifically related to a de-
crease in security system effectiveness. Another event, identified
by an inspector, involved an isolated error on the part of a plant
employee, who was not a member of the security force. This event
should have been reported under 10 CFR 73.71, but was not and a
violation was cited. Yet another event, also identified by an in-
'
spector, involved equipment failure and required reporting to the
NRC in accordance with the licensee's procedures and commitments.
These latter two events are indicative of possible confusion in the
licensee's event reporting procedures. All security events were
properly responded to and appropriate compensatory security measures
were implemented.
In summary, the Security Department was a well organized, profes-
sional and compentent group with excellent management support.
2. Conclusion
Rating: Category 1.
'
Trend: Consistent.
3. Board Recommendation
Licensee:
None.
NRC
None.
. . . - -
- . - . _- . - - - - - _ __ .__ . .- ._ .
.
j.
.
27
.G. Refueling, Outage Management and Engineering Support (841 hours0.00973 days <br />0.234 hours <br />0.00139 weeks <br />3.200005e-4 months <br />, 16%)
'
1. Analysis
The previous SALP identified staff training weaknesses in ASME code
requirements regarding appropriate NDE testing requirements for
electrical penetrations. An additional problem was noted in this
- area during this assessment period in that NDE equipment calibration
i
procedures and recording criteria were found not to agree with ASME
Section XI requirements. This indicated a need for additional
training for. personnel responsible for the review and approval of
NDE procedures. Training was conducted. Because additional elec-
trical penetration work of this nature has not been conducted, the
effectiveness of the training has not been assessed.
'
Two refueling outages were conducted during the evaluation period
i (Spring 1985 for Unit 1 and Fall 1985 for Unit 2). Additionally,
there were several unscheduled outages on both units. Outage acti-
vities observed by resident and regional inspectors included: outage
coordination meetings, steam generator tube eddy current testing,
replacement of salt water system heat exchanger channel heads, in-
stallation of reactor vessel level monitoring system, fuel loading,
new fuel inspection, containment local and integrated leak rate
testing, main steam isolation and safety valve maintenance, QC in-
l spection activities, installation of reactor cavity seal and steam
a
generator nozzle dams, outage radiological protection, In Service
Inspections, and core loading verification.
Refueling outages were well planned and controlled. A strong effort
was made to receive engineering design change packages on site at
an earlier point to avoid last minute perturbations in outage re-
sources and schedules. There was strict adherence to the schedule '
of activities, and good communication between licensee and contrac-
tor work groups. Daily outage meetings were attended by both cor-
z porate and site management. Those meetings were succinct and ef-
fective. The major portion of the fall outage was completed on or
ahead of schedule.
The good practice of utilizing senior licensed operators to coor-
dinate operations and maintenance activities was continued and fur-
ther developed. This is now a permanent staff function (utilizing
a shift supervisor) with an additional individual assigned during
refueling outages. The recent reorganization centralized the outage
coordination, operations-maintenance coordination, and the tagging
functions into a single group within the operations department.
Improvements were made in the scheduling / control of post maintenance
. testing.
1
i
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, , _ , , , _ - . -. _. _ _ _ - - _ _ _ - _ - - - , . . _ .
.
.
28
The company reorganization late in the assessment period brought
about major changes to the engineering area. Formerly, engineering
functions were carried out by three major departments. Some func-
tions were conducted out of the corporate office in Baltimore.
These functions were consolidated into one department and will all
be conducted at the plant site. This is expected to reduce coordi-
nation problems and minimize duplicate efforts. The licensee showed
good planning in developing a transition program which anticipated
losses of personnel due to job relocation and company reorganization.
A good initiative was the licensee adoption of the systems engineer
concept.
Within the engineering area, another good licensee initiative was
the additional emphasis being placed on improvements in design
checklists and documentation of facility changes (this effort was
in part due to the identification of documentation deficiencies
noted by a NRC Equipment Qualification inspection team) and in-
creased involvement of design engineers in system walkdowns (as a
way of reducing the number field engineering changes required).
To enhance shift staffing, an initial group of four engineers were
undergoing a full time, 18 month training program leading to a
senior operator license and Shift Technical Advisor (STA) qualifi-
cation. Upon program completion those engineers will join the
operations group on shift as STA's.
During the 1985 refueling outages, marked human factor. improvements
were made to control room panels. These included upgr<a.d indica-
tor / switch labeling, board mimic diagrams, demarkation of related
instrument clusters, color coding, permanent information postings,
and information on instrument response characteristics to losses
of power. Additionally, the control boards were cleaned and painted.
As stated in the Chemistry and Radiological Functional Area, signi-
ficant deficiencies were identified in the PASS system. In addition
to the problems noted in that area, the licensee did not subject
the implementation of PASS modifications to thorough or technically
sound review or test procedures. This was indicative of a program-
matic breakdown in the licensee's program for verifying and vali-
dating system performance. Further, in line analytical instruments
and certain valves necessary to establish sample flow were inoper-
able. The dominant causal factor was a lack of strong overall
managerial control to assure that sufficient priority and resources
were provided for identification and correction of system problems.
A follow up inspection indicated that the deficiencies associated
with PASS were an isolated case. That is, similar deficiencies did
not exist with other NUREG-0737 modifications.
__ -- .. ._ _
. --_. - -
.
.
29
PASS is discussed in this section of the assessment because:
(1) of the insufficient system testing noted above; (2) an under-
standing of what system constituted the " alternate" sampling method
was not :learly communicated from the engineering organization to
the plant; (3) the system was declared operable without procedures
and training and (4) because it was representative of a problem the
company recognized and was attempting to solve in the future through
their development of the systems engineer concept. That is, the
burden of solving this complicated system problem was placed on
operating / maintenance line supervisors who are charged with many
other responsibilities and who lacked sufficient technical support.
Two Equipment Qualification Inspections were conducted during the
period. The NRC inspection team conducting the second inspection
concluded that there was an apparent lack of management attention
in the establishment of a viable EQ program. This was evidenced
by the failure to take adequate corrective action for a deficiency
identified during the previous EQ inspection (qualification of
Rockbestos Coaxial Cable not established) and by the large number
of potential enforcement / unresolved /open items identified during
the follow up inspection.
Apparent weaknesses were noted in engineering support for the In-
strument and Controls area. Specific indicators included: (1) a
design error made in a modification to the Engineered Safety Fea-
tures Logic Cabinets, (2) difficulty experienced by the licensee
in designing a means for conducting in-cubicle testing of reactor
trip breakers, and (3) long standing problems with Unit 2 main
feedwater control circuitry.
2. Summary
In summary, routine outage activities were well planned and co-
ordinated. A strong management influence was involved in decision
making where significant repercussion may result. Good communica-
tion and orchestration of activities was demonstrated resulting in
meeting schedules while minimizing rework and man-rem exposure.
!
Numerous upgrades of the plants were successfully made without com-
plication. However, two areas, Post-Accident Sampling System and
, Environmental Qualification of Equipment lacked sufficient manage-
!
ment attention.
Changes due to reorganization and development of the system engineer
concept, as well as other recent program developments, prevented
recurrence of problems where multi-disciplines required coordination
of management support.
I
- - _- . . . _ _ -- .. = - - . . - _.
.
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.
30
i NRC involvement was necessary to identify deficiencies in the PASS
i and the Equipment Qualification program. The licensee should have
recognized these problems through their own initiative.
3. Conclusion
Rating: Category 2.
Trend: No basis.
4. Board Recommendation
,
Licensee:
'
None.
NRC:
Schedule a meeting with the licensee to discuss licensee plans for
better integration of engineering support into modification and I
outage activities.
i
,
1
i
Y
!
,
,
i-
, -
_ _ - . _ - - _ _ - _ _ _ - . - . . . - - _ _ _ _ _ _ , _ . - . _ - . _ _ _ =,-- _. _.
.
.
.
.
31
H. Licensing Activities
1. Analysis
During the SALP evaluation period, the licensee continued to show
good management overview in the area of licensing activities. The
majority of the licensing actions completed during the SALP period
were resolved within the licensing group at Calvert Cliffs (or via
technical experts utilized by the licensing group). In the few in-
stances where matters were referred to the licensee's upper manage-
ment, these individuals proved to be well informed and helpful in
resolving questions of a corporate nature. For example, the licen-
see's Vice President for Supply was directly involved in the reso-
lution of the Radiological Effluent Technical Specifications (RETS)
,
d
and problems associated with Post-Accident Sampling. The licensee's
management also showed itself to be innovative and forward thinking.
During the SALP period, the license (1) obtained a full 40 year
operating license for Calvert Cliffs, Units 1 and 2; (2) worked
diligently to establish an industry position on station blackout;
and (3) requested a reduction in their emergency planning zone from
10 miles to 2 miles.
A summary of licensing activities is contained in Table 7. The
licensee's submittals were usually timely and of high quality. Of
particular note was the licensee's treatment of the "significant
hazards consideration" standards of 10 CFR 50.92, " Issuance of
Amendments." During the SALP period, the licensee substantially
improved the way in which "significant hazards considerations" were
addressed and now presents detailed safety analysis and plant-speci-
fic design information in addressing the standards of 10 CFR 50.92.
The licensee continued to maintain a significant technical capabil-
ity in almost all engineering and scientific disciplines necessary
to resolve items of concern to the NRC and the licensee. The lic-
ensee continued to utilize the services of Combustion Engineering
for accident analysis. However, the licensee was improving its
accident analytic capability and had submitted a request for review
and approval of the RETRAN model for Calvert Cliffs. The NRC also
benefited from the licensee's technical capabilities as a result
of NRC's request for comments and/or participation in the following:
--
Seismic Qualifications of Equipment (USI A-46)
--
Safety Implications of Control Systems (USI A-47)
--
Pressurized Thermal Shock (USI A-49)
The licensee continued to respond promptly to all NRC staff initi-
atives. During the SALP period, the licensee assisted the NRC in
resolving a number of multi plant (generic) items and TMI Action
.
.
32
items. In each case, the licensee carefully evaluated the item in
question to assure the degree of applicability to Calvert Cliffs.
Where requirements were generic rather than plant-specific, the
licensee diligently negotiated changes in requirements to assure
that the final requirements (e.g., Technical Specifications or
equipment design) fully reflect the Calvert Cliffs plant design.
In some cases, the licensee's upper management was involved in final
negotiations. In all cases where the licensee's position did not
meet the final NRC position, the licensee changed their position
to achieve conformance.
During the SALP period, one enforcement action was directly related
to licensing activities. The subject enforcement resulting from
the inadequacy of the post accident sampling system (PASS). This
action was significant from a licensing standpoint in that the TS
was proposed for an unproven system and the licensee should not have
proposed the TS until the PASS had been shown to be reliable. Sec-
tion G, " Refueling, Outage Management, and Engineering Support,"
presents additional details on this issue.
In summary, the licensee's licensing activities were conducted by
a well staffed and well trained group resulting in an overall effi-
cient operation. Management overview was obvious in that the lic-
ensing group was, for the most part, well integrated into other
plant activities and licensing activities reflected a uniform ap-
proach. Upper management became directly involved in licensing ac-
tions only rarely to assist in resolving potential deadlocks. The
licensee is to be commended for the diligent way in which multi-
plant (generic) and TMI Action Items were resolved and the willing-
ness of the licensee to compromise when necessary to achieve agree-
ment with NRC positions.
2. Conclusion
Rating: Category 1.
Trend: Consistent.
3. Board Recommendation
Licensee:
None.
NRC:
None.
l
l
!
I
.
.
33
I. Assurance of Quality
1. Analysis
During this assessment period, management involvement and control
in assuring quality is being considered as a separate functional
area for the first time and continues to be one evaluation criterion
for each functional area. The various aspects of Quality Assurance
Program requirements have been considered and discussed as a integ-
ral part of each functional area and the respective inspection hours
are included in each one. Consequently, this discussion is a synop-
sis of the assessments relating to quality work conducted in other
areas. However, it is not solely an assessment of the QA/QC de-
partments.
The licensee has dedicated significant resources and emphasis to
the assured quality of their work, and emphasizes that quality is
a line function. Increased emphasis was placed on assessing effec-
tiveness of plant programs. For example, early in the SALP period,
licensee management effectively used QA personnel to perform an in
depth auditing effort to identify administrative and technical de-
ficiencies in surveillance test procedures (STP's). The Quality
Control staff was extensively involved in monitoring corrective
maintenance, surveillance testing, and modification activities.
The effectiveness of the licensee's QA organization was shown by
the identification of improper vendor substitutions of non-safety
grade air filters for safety grade filters.
QC coverage of both primary and secondary maintenance and surveil-
lance activities was noted to be extensive.
Routine audits performed by the QA staff were well planned and
thorough, and audit findings were resolved within a reasonable time
frame. However, audit findings have routinely appeared to be minor
in nature with little impact on the specific program. Audits were
only of tradational areas / departments and generally did not assess
nor "second guess" management /POSRC decisions. Audits were often
quite superficial and presented additional paperwork and a burden
, to various departments with several " nits" rather than identifying
!
real problems, attempting to identify the root cause(s), and pro-
viding appropriate recommendations.
Management and the onsite review and offsite review committees were
not effective in their reviews to assure quality in the acceptance
of the Post Accident Sampling System considering the many problems
associated with it, and in the inadequate maintenance of the En-
vironmental Qualification of components. The Plant Operation and
Safety Review Committee was often less than effective in implement-
,
ing their role as a safety committee to ensure understanding of root
!
l
t
- _ _ _ _
.
.
34
causes of several plant trips (see Maintenance functional area).
Considerable NRC attention was required prior to the licensee in-
itiating adequate action regarding several potential safety issues
(see Operations functional area). Quality in the initial decisions
for corrective action was not effective in preventing recurrence
of loss of shutdown cooling, feed pump / reactor trips, feedwater
heater level / reactor trips, and repetitive shutdowns due to main
steam isolation valve problems (see Table 6).
Independent of the above, as a result of a licensee reorganization,
major changes were made (late in the period) which are indicative
of effort to improve the quality effectiveness as follows:
(1) To provide greater depth of insight, a pilot program was im-
plemented using senior licensed individuals (of the operations
department and currently assigned to shifts) to conduct QC
surveillances of operational activities. A similar program
was implemented in the chemistry area.
(2) QC personnel were transferred from the QA department to line
departments (however, they remained as separate groups within
those departments to preserve independence). This was done
to provida more effective (less adversarial) working relation-
ships between QC and line personnel. The licensee wanted to
provide the line departments with an improved tool to ensure
work was being accomplished correctly under the philosophy that
quality is a line function. Enhanced cross training programs
for QC and line groups was initiated.
(3) QC controls are now being provided for selected non-safety
related maintenance activities.
(4) Efforts were made to improve audit effectiveness by increased
QA supervisor participation in audit planning and review and
by making audits more technical in nature.
(5) Audits similar in nature to recent NRC IDI and PAT team in-
spections are planned.
l (6) Material receipt inspections will be expanded to include in-
i
creased dimensional checks of parts.
'
(7) The QA staff was strengthened by the addition of a General
Supervisor with previous experience as the General Supervisor
of Operations. Additionally, a senior licensed engineer was
added to the staff.
l
l
i
i
_ _
- _ _
.
.
35
(8) The practice of conducting audits of areas of special concern
to licensee management was continued (e.g. compliance of NUREG
0737 requirements, Reactor Coolant Pump overhaul activities).
In summary,'although an extensive quality program existed throughout
the organization, the. visible contribution incorporating quality
in the important safety issues appears lacking. Quality effective-
ness was also limited in the line functions, specifically in the
I&C area, resulting in numerous plant trips. New initiatives were
implemented in this area late in the assessment period.
2. Conclusion
Rating: Category 2.
Trend: No basis.
3. Board Recommendation:
Licensee
None.
NRC
None.
- - . _ _ -
.
.
36
J. Training and Qualification Effectiveness
1. Analysis
Although attributes of this topic are discussed in each SALP func-
tional area, the topic here is segregated because of its importance,
and to provide a synopsis of the effectiveness of the training and
qualification programs. Training effectiveness was measured pri-
marily by the observed performance of licensee personnel and, to
a lesser degree, by reviews of program adequacy. The discussion
below addresses three principle areas: licensed operator training,
non-licensed staff training, and the status of INPO training accre-
ditation.
INP0 accreditation for the site was scheduled for completion by the
end of June 1986. Three operator training programs and health
physics and chemistry were approved by the end of the assessment
period. Instrument and Controls, maintenance electricians and the
STA programs v re submitted in January 1986. The final two programs
for mechanica' anaintenance and the technical staff were due to INP0
by June 30, 1986.
Effectiveness of training for most departments was good as evidenced
by few personnel errors, a low man rem dose rate and timely assess-
ment and response to abnormal occurences by plant operators. Train-
ing in the Maintenance Mechanical area was less than effective.
A lack of engineering support to provide torque specifications re-
sulted in over torquing pressurizer spray valve fasteners. Many
components may remain over torqued because of the duration of the
maintenance program without appropriate training in this area.
Maintenance training was also noted to be lacking with respect to
rebuilding Reactor Coolant Pump Seals when the resident inspector
observed a component being installed backwards.
Other areas where training was provided but appeared less than ef-
fective was within the Instrument and Controls Department. Training
appeared comprehensive and attendance was good. Facilities and
support appeared appropriate. However, several personnel errors
were noted where technicians failed to follow procedures causing
a loss of shut down cooling, recirculation actuation signals, and
other Emergency Safety Feature actuations. Additionally, several
plant trips occurred due to grounds on control systems or undeter-
mined causes associated with control mechanisms which instrument
and controls troubleshoots often unsuccessfully.
Reviews of training for non-licensed staff indicated that great
strides were being accomplished in an area where signiiicant weak-
nesses were noted in licensee's prior performance related to main-
'
.- tenance technical training. The licensee recognized the maintenance
,
department's previously weak training program and, as part of the
e
-- . - - - . - - . . _ . - - _ - -- --. .. _- - - - - ..
.
37
j. -
i site effort to become INPO accredited, included considerable spe-
cialized training improvements for reactor coolant pump seal re-
placement, rebuilding safety valves, control valves and actuators,
i fasteners and coupling and machinery alignment. (Problems in these
!
areas in the past led to unit shut downs or aggravated operations.)
- A machinery mechanic training and qualification program was devel-
! - oped bringing a formalized qualification program for levels 1, 2,
and 3 mechanics. This ensured a formal base line knowledge in basic
math, plant systems, print reading, first aid and radiological
safeguards type material for all personnel. Equipment maintenance
qualifications, with courses provided for each type of valve, pump,
i
compressor, and actuator within the plant up to level 3 training
i on reactor assembly / disassembly, governors, diesel generator equip-
! ment and electrohydraulic controls were also provided. Schedules
provide for classroom, laboratory, on the job, and recurring train-
ing. These qualification programs were or were being developed for
each area within the maintenance department, health physics and
operations.
- In addition to the recent task analysis, procedure development and
-
qualification program, the licensee dedicated significant hardware
resources to training beginning with the site specific simulator
primarily for licensed operators. Both the maintenance electricians
and instrument and control had training laboratories with state of
,
the art training aids provided. Functional laboratories were pro-
4
vided for health physics and chemistry and maintenance. Mockups
, were provided for steam generator primary side man ways, reactor
coolant pump seal and various valves.
,
Although the licensee recognized and implemented corrective action .
for the previously marginal training in the maintenance area, and
, supplemented the training programs of other areas with INPO accre-
ditation, the effects of the accreditation were yet to be seen.
,
Discussions with licensed operators reflected little knowledge of
probablistic risk assessment. Operators were not cognizant of
i systems / components that are significant risk contributors or what
l possible effects working on these systems / components might have.
!
l In summary, training programs were in place and were being upgraded
I with INPO accreditation nearly complete. Appropriate resources and
! management attention were dedicated. Significant improvements were
made in the previously weak maintenance program, however effective-
ness of improvements was yet to be seen,
f
i
T
.- - - . .~ . . _ .
- . . _ . . _ . _ - . - _ . . _ - . . . . .
_ .. . _ . . . - . . _ - . . . . . .. . _ .
.-
i
4
,
k
! 38
!
.
1
2. Conclusion
.
'
- Rating
- Category 2.
Trend: Consistent.
2
1, 3. Board Recomendation
N
! Licensee !
,
! None.
!
,
NRC
5
I
None.
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, - . _ _ . _ . . . _ . , _ . _ . . . . . . _ _ . . _ _ _ . _ _ _ , , . . _ _ _ _ - - . _ - . _ , _ . - _ . _ . _ . _ . . _ . . _ . . . . - . _ _ _ . _ _ _ _ _
.
6
39
V. SUPPORTING DATA AND SUMMARIES
A. Investigations and Allegations Review
During this assessment period three allegations were received. Two al-
leged adverse background information for (2) contractor employees. This
information was provided to the licensee for further investigation. In-
formation gained from follow on investigation led to the removal of site
access for one of the individuals. In the second case, the licensee
determined no action was necessary.
The third allegation, regarding an improper entry into high radiation
areas, was received near the end of the SALP period and was still under
review.
Inspector effort was continued on five allegations made by a single wor-
ker at the end of the previous SALP period, which stated that improper
administrative control actions caused the worker to receive a radiation
exposure in excess of regulatory limits. The allegations were partially
substantiated and two violations were issued.
An investigation was conducted by the Office of Investigations regarding
improper vendor substitution of commercial grade HEPA filters for safe
grade filters.
B. Escalated Enforcement Actions
1. Civil Penalties
One civil penalty was issued on September 26, 1985 resulting from
identification of significant deficiencies in the Post Accident
Sampling System (PASS).
2. Orders
None.
3. Confirmatory Action Letters
f
None.
C. Management Conferences Held During the A".sessment Period
A management meeting (July 11, 1985) and, subsequently an enforcement
conference (August 14, 1985) was held regarding deficiencies in the PASS
System.
A 4 *.a _*= %a5 a-- - -J,41r42I.-a+ _.4__a- . _ -e aM _ Ma.-m-- . 14...J_a.24 .2 _ h _. - -w . _i~_a
.4._mu
,
,
. 40
i
i
, D. Licensee Event Reports (LERs)
1
, Tabular Listing .
-
TYPE OF EVENTS Unit 1 Unit 2 i
A. Personnel Error. . . . . . . . . 4 . . . . . . 3
B. Design / Man.Constr./ Install . . . 6 . . . . . . 2
'
C. External Cause . . . . . . . . . 2 . . . . . . 1
D. Defective Procedure . ..... 5...... 0
, E. Component Failure . . ..... 3...... 5
X. Other . . . . . . . . ..... 2...... 6
'
Total . 39
4
!
Licensee Event Reports Reviewed:
i'
Report Nos. 317/84-13 through 86-02; and 318/84-08 through 86-03. ,
i.
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-
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. _ _ _ _ _ _ __ __ . ._ __
-,
a
+
-
TABLE 1
- . INSPECTION REPORT ACTIVITIES
,
UNIT 1/ UNIT 2 INSPECTION
REPORT NUMBERS HOURS AREAS INSPECTED
{
84-26/84-26 108 IE Bulletins 79-02, 79-04, 79-07, and 79-14
! 84-27/84/27 289 Equipment Qualification
84-28/84-28 32 Chemistry
84-30/84-30 40 Operator Examination
84-31/84-31 169 Routine Resident
84-32/84-32 44 Radiation Protection Program
85-01/85-01 214 Routine Resident
85-02/85-02 238 Routine Resident
85-03/85-03 0 Cancelled
85-04/85-04 81 Non-License Training and QA Program
85-05/85-05 28 Radiation Protection Pre-Outage
85-06/85-06 56 Environmental Protection Program and
Training
85-07/85-07 220 Routine Resident
-85-08/85-08 68 Physical Security
85-09/85-09 259 Routine Resident
85-10 67 Containment Leakage Testing Program
85-11 37 In Service Inspection
85-12/85-10 50 Radiation Protection
85-13/85-11 120 Routine Resident
85-14/85-12 64 Radiation Environmental Monitoring
85-15/85-13 272 Routine Resident
- . - _ _ _
.
. . .
_ ___ _-
.
T-1-2
UNIT 1/ UNIT 2 INSPECTION
REPORT NUMBERS HOURS AREAS INSPECTED
85-16/85-14 190 TAP PASS, Effluent Monitors
85-17/85-15 20 Radiation Safety
85-18/85-16 180 PASS
85-19/85-17 64 Radioactive Liquid and Gaseous Effluent
Program
85-20/85-18 0 Enforcement Conference
85-21/85-19 0 Cancelled
85-22/85-20 245 Environmental Qualification
85-23/85-23 40 Operator Examinations
85-24/85-21 210 Routine Resident
85-25/85-22 190 Emergency Preparedness
85-26/85-24 41 Safeguards
85-27/85-25 56 Radiation Protection Pre-Outage
85-28/85-28 237 Routine Resident
85-29/85-30 33 Transportation
85-31 42 Refueling Activities
85-30/85-32 186 Routine Resident
85-31/85-26 31 Radiation Protection
85-32/85-27 190 Operator Requalification Program
85-33/85-33 126 Local Leak Rate Tests and Integrated Leak
Rate Tests
85-34/85-34 185 Routine Resident
85-35/85-35 29 Radiation Protection
86-01/86-01 49 IE Bulletin 80-11, Masonry Wall Design
86-02/86-02 68 Dosimetry Inspection
. .. . _ - - ... - . ,_ - - - . - - . --_ _ _ -
.
.
j T-1-3
'
UNIT 1/ UNIT 2 INSPECTION
REPORT NUMBERS HOURS AREAS INSPECTED
86-03/86-03 136 Routine Resident
86-04/86-04 32 Physical Security
86-07/86-07 220 Routine Resident
TOTAL HOURS 5258
i
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,
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.
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.
.
TABLE 2
INSPECTION HOUR SUMMARY (10/1/84 - 4/30/86)
HOURS % OF TIME
1. Plant Operations........................... 1295 24.6%
2. Chemistry and Radiological Controls. . . . . . . . 901 17.0%
3. Maintenance................................ 837 16.0%
4. Surveillance............................... 885 16.8%
5. Emergency Preparedness..................... 211 4.0%
6. Security and Safeguards.................... 288 5.5%
7. Refueling...................... ........... 841 16.0%
8. Licensing Activities....................... NA NA
9. Assurance of Quality....................... NA NA
10. Training and Qualification Effect.......... NA NA
TOTALS 5258 100%
1
..
.
TABLE 3
VIOLATIONS (10/1/84 - 4/30/86)
A. Number and Severity Level of Violations
Total Violations 20
B. Violations Vs. Functional Area
Severity Levels
Functional Areas I II III IV V
1. Plant Operations 1 4 2
2. Chemistry and Radiological Controls 4 1
3. Maintenance
4. Surveillance 2 1
6. Security and Safeguards 3
7. Refueling, Outage Management, and
Engineering Support 1 1
8. Licensing Activities _ __ _
Totals 2 14 4
Total Violations 20
.
v.
T-3-2
C. Summary
Inspection Inspection Severity
Number Dates Requirements Level Area Subject
317/318
84-26/82-26 10/1-5/84 Dev. Refuel Piping systems'identi-
fled as Reactor Coolant
and the pressurizer
surge lines had not
been. inspected and
verified for agreement
with corresponding
seismic analysis on
Calvert Cliffs Units.
84-32/84-32 11/26-30/84 TS 6.8 IV Rad Failure of workers to
comply with Special
Work Permit
85-01/85-01 12/18/84- TS 6.12 IV Rad Failure to Post High
1/22/85 Radiation Area in Five
Foot West Penetration
Area.
85-09/85-09 4/1-5/6 TS 3/4 9.3.9.3 V Ops Source Range Nuclear
Flux Monitor was not
Audible in the Control
Room.
85-13/85-11 5/6-6/17 TS 6.8.la IV Ops Two instances of per-
Surv sonnel failure to fol-
low procedures resulted
in: U1 Shutdown Cooling
Flow Loss when RCS
Pressure Increased
Above 284 PSIA; Two
of Four U2 RWT Level
Switch Channels were
Tripped at one time
during STP M-220-2.
..
- _ . _ __
e
T-3-3
Inspection Inspection Severity
Number Dates Requirements Level Area Subject
85-16/85-14 6/24-6/28 NRC Order III Refuel Significant deficien-
TS 3.7.13 III Ops cies associated with
85-18/85-16 7/16-7/26 NRC Order IV Refuel PASS, e.g. inadequate
TS 4.3.3. IV Surv testing, design, train-
TS 6.15 IV Ops procedures. Inadequate
protective sleeving
(EQ) for in-containment
hi range radiation
monitors. Missed sur-
veillance testing on
main vent iodine and
particulate sampler.
'
85-17/85-15 7/1-3/85 10 CFR 20.201 IV Rad Worker received radi-
ation dose higher than
allowed for condition
where NRC Form 4 not
completed.
1
10 CFR 20.201 IV Rad Improper reporting of
above event.
86-03/86-03 1/20-3/3 TS 3.6.4.1 IV Ops U1 1-SV-6529 Discovered
!
to be Open Without
Administrative Control.
(Containment Isolation
Valve).
,
'
86-04/86-04 2/18-21/86 Sec. Plan IV Sec. Failure to check an
alarm.
Sec. Plan IV Sec. Failure to report.
i
86-05/86-05 3/3-7/86 TS 6.8.1 V Rad Procedure for stand
up whole body counter
not properly approved.
TS 4.6.3.1 IV Surv Inadequacy in lab
analysis program for
charcoal absorber
material.
.
_ - . - .- . . . . _
d
T-3-4
Inspection Inspection Severity
) Number Dates Requirements Level Area Subject
86-07/86-07 3/4-4/30 10 CFR 50 V Surv Unit 1 High Pressure
Safety Injection Pump
Discharge Pressure
gauge inadequate for
'
use, (out of calibra-
tion) to demonstrate
functional acceptance
- of safety systems.
'
10 CFR 50 V Ops Installed instrument
not tagged or labelled
indicating date of
'
.
'
calibration or identify
of person performing
calibration.
10 CFR 50 IV Ops Post maintenance test
App 8 accomplished by pro-
cedures not appropriate
to the circumstances
4 resulting in inadvert-
ent isolation of Unit
2 shut down cooling
system. Ineffective
corrective actions
, following earlier
events led to recurring
losses of shut down
cooling.
Sec. Plan V Sec Security violation.
,
A
. _ _ . . _ .
_ . - . . -- - -_ _- . .
, _ _ . __ . .
_ - - . -.
. . . . _ _ _-. .____ _ _ -_ _ _.
.. .< ,
~
..
., n '
.
1
h
TABLE 4
TABULAR LISTING:0F LERS BY FUNCTIONAL AREA
AREA -
NUMBER /CAUSE CODES
1. Plant Operations 4/A 0/8 3/C 0/D 0/E 0/X
2. Chemistry and Radiological Controls 0/A 0/8 0/C 0/D 0/E 0/X
3. Maintenance - _
1/A 4/B 0/C 3/D 7/E 3/X
4. Surveillance 2/A 4/B 0/C 2/D 1/E 5/X
5. Emergency Preparedness 0/A 0/8 0/C 0/D 0/E 0/X
'
6. Security and Safeguards 0/A 0/B 0/C 0/D 0/E 0/X
s
7. Refueling, Outage Management and Engineer Support 0/A 0/8 0/C 0/D 0/E 0/X
,
8. Licensing Activities '
0/A 0/B 0/C 0/C 0/E 0/X
,
Cause Codes U1 U2 Total
A. Personnel Error 4 3 7
8. Design / Man./Const. Install. 6 2 8
C. External Cause 2 1 3
D. Defective Procedure 5 0 5
':
E. Management / Quality Assurance Deficiency 3 5 8
X. Other 2 6 8
4
Totals 22 17 39
.
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7
%.
g
- .. _
. .. . ,. -
- _ _ _
o.
,
TABLE 5 ,
LER SYN 0PSIS
LER NUMBER SUMMARY DESCRIPTION
UNIT 1
84-13 Loss of Circulating Water Caused by Sea Nettle Impingement
84-14 Battery Inoperable
84-15 Loss of Circulating Water Caused by Sea Nettle Impingement
84-16 HPSI Injection Leg's Flow Imbalanced
84-18 #11 MSIV Inoperable
)
84-19 Failure of #12 MSIV to Fully Close during Surveillance
85-01 Excessive Safety Injection Tank Check Valve In Leakage
85-02 Reactor Trip on Low Steam Generator Water Level Condition Resulting
from a Temporary Loss of Main Feed Water
85-03 MSIV Setpoints Out of Tolerance
85-04 ESFAS Occurred During Surveillance Testing with Unit in Mode 4
85-05 Inadvertent Initiation of Steam Generator Isolation
85-06 UGS Removal Without Fuel Handling Supervisor Present
85-07 HPSI Injection Leg's Flow Imbalanced
85-08 Reactor Trip Caused by Moisture Separator High Level
85-09 Reactor Trip on Low Steam Generator Water Level
85-10 Reactor Trip caused by Improperly Set Main Turbine Thrust Bearing
Wear Detector s
85-11 MainTurbineTripDuetoanUndetermhnedCause
85-12 Main Turbine Trip Due to a Grounded Feed Water Heater Level Control
Switch
85-13 RCP Shaft Seal Bleed Off Line Weld Failure
85-14 Control Room Ventilation Damper Failure
/
^
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1
,a
0
T-5-2
LER NUMBER SUMMARY DESCRIPTION
86-01 Reactor Trip Caused by Failure of TCB #2 During Surveillance Testing
86-02 Inadvertent Closing of Shutdown Cooling Return Valve
Unit 2
84-08 Reactor Trip Due to Loss of #22 Main Feed Water Pump.
Cause Unidentified.
85-01 Manual Trip Caused by Degradation of #21A Reactor Coolant Pump
,
Shaft Seal
85-02 Reactor Trip Caused by an Inadvertent Actuation of #21A RCP Over
Current Device
85-03 Incorrect Fastener Material used in Pressurizer Spray
85-04 Control Room Post LOCI Filter System Inoperable
85-05 Recirculation Actuation Signal Inadvertent Initiation
85-06 Inoperable Diesel Generators
85-07 Failure to Perform Required Surveillance on Noble Gas Monitor
85-08 Failure of #21 MSIV to Fully Close during Surveillance Testing
85-09 Blockage of Saltwate Flow to Service Water Heat Exchanger #21
85-10 Pressurizer Safety Valve Setpoint Out of Specification
85-11 Main Steam Safety Valve Set Points Out of Specification
85-12 Reactor Trip on Low Steam Generator Water Level
85-13 Inadvertent Initiation of Engineered Safety Features During Mode
6
86-01 Violation of TS for Pressurizer Over Pressure Protection during
Cold Shutdown Conditions
86-02 Inadvertent Trip of Main Turbine from Engineering Safety Features
Actuation System ,
86-03 Inadvertent Engineered Safety Features Actuation Due to Failed
Logic Module
.
O
TABLE 6
UNPLANNED AUTOMATIC TRIPS AND FORCED OUTAGES
DATE AND
UNIT POWER LEVEL DESCRIPTION CAUSE
1 10/2/84 Manual trip following accumulation of jelly Design.
100% fish o,n intake structure screens, to avoid
damage to screens and circulating water
pumps and low condenser vacuum condition.
2 10/3/84 Unit tripped on low steam generator water FW control prob-
92% level due to loss of #22 main feed water problems (possibly
pump. The exact cause of pump trip could due to grounds).
not be determined but was believed to origi-
nate in the automatic speed control circuitry.
1 11/20/84 Manual trip following accumulation of jelly Design
100% fish on circulating water screens, to avoid
damage to screens and circulating water pumps
and low condenser vacuum conditions.
1 12/12/84 Controlled shutdown due to a concern that Equipment prob-
100% #11 Main Steam Isolation Valve might be it. lem (possible
inoperable. design / maintenance
related).
1 01/16/85 Controlled shutdown to repair Safety Injec- Possible main-
100% tion Tank check valve leakage. tenance deficiency.
1 02/01/85 Reactor trip on low steam generator water Miscommunication
100% level following loss of both main feed water between operator
pumps (MFWP). MFWP trips were caused by and control room.
operator error in mistakenly opening a con-
trol power breaker.
2 04/25/85 Precautionary manual trip by operator due to Precautionary
100% failed Reactor Coolant Pump seal. trip.
2 05/05/85 Reactor trip on low reactor coolant flow due Random failure.
55% to loss of Reactor Coolant Pump #21A.
2 05/17/85 Precautionary shutdown to inspect and re- Precautionary (to
100% place pressurizer spray valve fasteners. correct mainten-
ance problem).
2 07/18/85 Controlled shutdown to repair two pin hole Weak B0P surveil-
100% size steam leaks on a cold turbine reheat lance.
line.
.
.
}
,
T-6-2
DATE AND
UNIT POWER LEVEL DESCRIPTION CAUSE
1 08/06/85 Reactor trip due to turbine trip as a result Personnel error.
17% of high level in Moisture Separator Reheater
(mispositioned isolation valve).
1 08/06/85 Trip due to low steam generator water level Personnel error.
28% due to operator difficulties in manually
maintaining steam generator level with posi-
tive moderator temperature coefficient.
1 08/07/85 Reactor trip caused by turbine trip due to Maintenance or
50% improper alignment of thrust bearing wear design.
detector.
1 09/30/85 Reactor trip caused by turbine trip due to Maintenance.
100% ground in feed water heater level circuit.
1 10/02/85 Reactor trip caused by turbine trip due to Continuing main-
100% continuing ground in feed water heater level tenance problem.
circuit.
1 10/09/85 Controlled shutdown due to cracked weld on Design or bad
100% Reactor Coolant Pump bleed off line. weld.
2 12/12/85 Trip on low steam generator water level due FW control prob-
46% to loss of #21 Main Feed Water Pump due to lems (possibly
faulty control circuitry, due to grounds).
1 01/13/86 Reactor trip due to malfunction of a Reactor Manufacturing
100% Trip Breaker during surveillance testing. error.
2 02/04/86 Reactor trip caused by turbine trip. Apparent spurious
100% SG high level
signal.
i
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.- .__,_ - - - , - . . . - - .
.
4
TABLE 7
SUMMARY OF LICENSING ACTIVITIES
1. NRR LICENSEE MEETINGS
March 27, 1986 Reactor Coolant System High Point Vent Technical Speci-
fications
December 13, 1985 Main Steam Line Safety Valves - Setpoint Problems
September 7, 1985 Control of Heavy Loads
August 26, 1985 Post-Accident Sampling System
July 10, 1985 Containment Purge and Vent. Valves
April 24, 1985 Masonry Wall Evaluation
March 20, 1985 Reactor Coolant Pump Seal Cooling
2. NRR SITE VISITS
March 20, 1986 Security Retraining and Inspect Plant Housekeeping
January 27-31,1986 Inspection of Boric Acid Subsystem
December 5, 1985 Inspect Plant Housekeeping
Sept. 23-26, 1985 Inspect Spent Fuel Pool Cooling System
August 26, 1985 Control Room Habitability Inspection
July 19, 1985 Post-Accident Sampling System Inspections (exit interview)
June 24, 1985 Security Retraining and Inspect Plant Housekeeping
April 4, 1985 Inadequate Core Cooling Instrumentation Inspection
February 8, 1985 Inspect Plant Housekeeping
January 16, 1985 Inspect MSIVs and Obtain Data on Recent Failures
3. COMMISSION BRIEFINGS
None.
J
c-
,
. J
T-7-2
4. SCHEDULAR EXTENSIONS GRANTED
March 31, 1985 Environmental Qualifications Schedule Extension
5. RELIEFS GRANTED
April 18, 1985 ASME Code - Common start for Calvert Cliffs Units 1 and
2 Programs
May 20, 1985 ASME Code - Pressurizer Spray Line Inspection
September 18, 1985 ASME Code - Reactor Coolant Pump Weld Inspection
November 14, 1985 ASME Code - System Pressure Tests
March 10, 1986 ASME Code - Pump Tests
6. EXEMPTIONS GRANTED
January 8, 1986 Appendix J to 10 CFR Part 50 - ISI/ILRT Schedule
7. LICENSEE AMENDMENTS ISSUED
April 14, 1986 License Amendments 117 and 99 - Miscellaneous TS Changes
(applications dated February 22, 1985 and October 25, 1985)
March 31, 1986 License Amendment 116 (Unit 1) - Incore Detector TS
February 20, 1986 License Amendments 115 and 98 - Containment Vent TS
February 19, 1986 License Anendments 113 and 96 - Post Accident Sampling
System TS
January 8, 1986 License Amendments 112 and 95 - ILRT/ISI Schedule
December 31, 1985 License Amendments 111 and 94 - Diesel Generator TS
December 30, 1985 License Amendments 110 and 93 - Organizational Charts
.
December 9, 1985 License Amendments 109 and 92 - Miscellaneous TS Changes
l
.
(application dated April 26, 1985)
4
- December 4, 1985 License Amendments 108 and 91 - Miscellaneous TS Changes
(application dated June 28, 2985)
November 21, 1985 License Amendment 90 - (Unit 2) Cycle 7 Reload
!
August 30, 1985 License Amendment 89 - (Unit 2) TS Changes in Support of
cycle 7 Reload
!
f
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,
O
T-7-3
August 26, 1985 License Amendments 107 and 88 - TS for TCS Leakage
August 1, 1985 License Amendments 106 and 87 - Alternate STA Qualifica-
tior.s
July 1, 1985 License Amendments 105 and 86 - RETS (Effluent Monitoring)
May 20, 1985 License Amendment 104 - (Unit 1) Cycle 8 Reload
May 16, 1985 License Amendments 103 and 85 - Miscellaneous TS Changes
(applications dated September 20, 1984 and January 31,
1985)
May 1, 1985 License Amendments 102 and 84 - License Expiration Dates
March 7, 1985 License Amendments 101 and 83 - Revised TS for Halon
Systems
February 22, 1985 License Amendments 99 and 81 - GL 83-37 (TS for TMI Action
Items)
February 14, 1985 License Amendments 98 and 80 - ILRT Schedule
January 14, 1985 License Amendments 97 and 79 - Miscellaneous TS Changes
(applications dated April 9, 1984 and June 29, 1984)
8. EMERGENCY TECHNICAL SPECIFICATIONS ISSUED
None.
9. ORDERS ISSUED
July 16, 1985 Order Modifying License Confirming Additional Licensee Commit-
ments on Emergency Response Capability (Supplement 1 to NUREG-
0737)
-
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