ML17174A797
| ML17174A797 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 07/12/1991 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17174A795 | List: |
| References | |
| 50-237-91-16, 50-249-91-15, NUDOCS 9107230173 | |
| Download: ML17174A797 (14) | |
See also: IR 05000237/1991016
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-237/91016(DRP); 50-249/91015(DRP)
Docket Nos.
50-237; 50-249
Licenses No.
Licensee:
Commonwealth Edison Company
Opus West I II
1400 Opus Place
Downers Grove, IL
60515
Facility Name:
Dresden Nuclear Power Station, Units 2 and 3
Inspection At:
Dresden Site, Morris, IL
Inspection Conducted:
May 17 through June 28, 1991
Inspectors:
W. Rogers
D. Hills
M. Peck
Approved By:
M. Phillips
J. Schapker
D. Butler
R. Lerch
R. Zuffa, Site Resident Engineer
Illinois Department of Nuclear Safety
c~~
B. L. Burg~
Projects Section lB
Inspection Summary
Date'
'
Inspection from May 17 through June 28, 1991 (Reports No. 50-237/91016(DRP);
50-249/91015(DRP)).
Areas Inspected:
Routine unannounced safety inspection by the resident
inspectors, regional inspectors, and an Illinois Department of Nuclear Safety
inspector of licensee action on previously identified items; licensee event
report; operational safety; monthly maintenance; monthly surveillance; safety
assessment and quality verification; events; training effectiveness; and report
review.
Results:
Two cited violations were identified.
One involved a failure to
incorporate appropriate instrumentation into the periodic calibration program.
The other involved a failure to meet reporting requirements.
One non-cited
violation was identified involving inadequate preparation of a 10 CFR 50.59
safety evaluation.
One open item related to the emergency diesel generators*
output .breaker logic design was identified.
9107230173 910715
ADOCK 05000237
Q
- *
Operations
Performance appeared adequate with LCOs met and tew personnel errors.
However, some reporting evaluation weaknesses were observed.
Maintenance/Surveillance
Maintenance activities were properly accomplished.
However, weaknesses were
apparen~ in the breadth and coverage of the instrument calibration
program.
Ra.die l ogi cal Protection
While observations were limited, no program or implementation weaknesses were
observed.
This SALP functional area was not addressed in this inspection period.
Security
While observations were limited, performance in this area remained good.
Safety Assessment ana Quality Verification
Performance appeared adr:quate with some weaknesses in the safety evaluation
process.
Engineering and Technical Support
This area was not addressed.
DETAILS
1.
Persons Contacted
Commonwealth Edison Company
- E. Eenigenburg, Station Manager
- L. Gerner, Technical Superintendent
J. Kotowski, Production Superintendent
E. Mantel, Services Director
D. Van Pelt, Assistant Superintendent - Maintenance
J. Achterberg, Assistant Superintendent - Work Planning
- G. Smith, Assistant Superintendent-Operations
K. Peterman, Regulatory Assurance Supervisor
- M.- Korchynsky, Operating Engineer
- 8. Zank, Operating Engineer
- J. Williams, Operating Engineer
- R. Stobert, Operating Engineer
T. Mohr, Operating Engineer
- M. Strait, Technical Staff Supervisor
L. Cartwright, Q.C. Supervisor
J. Mayer, Station Security Administrator
D. Morey, Chemistry Services Supervisor
D. Saccomando, Health Physics Services Supervisor
F. Kanwischer, Services Superintendent
- D. Gulati, Master Instrument Mechanic
- 8. Viehl, Nuclear Engineering Department Supervisor
- K. Yates, Onsite Nuclear Safety Group Administrator
K. Kociuba, Nuclear Quality Programs Superintendent
- T. Gallaher, Nuclear Quality Programs Engineer
- Denotes those attending the exit interview conducted on June 28, 1991,
and at other times throughout the inspection period.
The inspectors also talked with and interviewed several other licensee
employees, including members of the technical and engineering staffs,
reactor and auxiliary operators, shift engineers and foremen, electrical,
mechanical and instrument maintenance personnel, and contract security
personnel.
2.
Previously Identified Inspection Items (92701 and 92702)
(Open) Open
I~em (50-237/90027-14(DRP)):
Perform sample inspection of
Systematic Evaluation Program (SEP) topic resolutions.
The inspector
completed verification of an SEP item during this inspection period as
discussed in paragraph 10.
This open item will remain open for remaining
SEP items pending completion of licensee confirmation of topic closures
and verification by the resident staff.
(Closed) Open Item (50-237/91003-03(DRP)):
Review the root cause and
planned corrective actions of an Advanced Nuclear Fuels (ANF) Spent Fuel
Pool (SFP) reload calculational error.
The error resulted from an ANF
3
core management engineer selecting the wrong xenon condition for the SFP
K-infinity calculation.
The error was not identified by CECo engineers
because their review was based on verifying that the K-infinity value was
reasonable and within Technical Specification requirements.
Planned
corrective actions included enhanced awareness within the ANF neutronics
team, regarding the quality of its work product, a change in calculational
methodology to reduce input requirements and the addition of a checklist
to provide greater sensitivity to calculational parameters.
In addition,
the Dresden Nuclear Engineering Group will develop formal guidelines for
reviewing reload documents.
The inspectors have no other concerns in
this area.
(Closed)
Unresolved Item (50-237/91009-03(DRP)):
Temporary alteration
(TA-II-7-91) on the Unit 2 high pressure coolant injection (HPCI) system
provided a direct interface between class IE electrical equipment and
non-safety measuring and test equip~ent (M&TE).
The 10 CFR 50.59 safety
evaluation for the temporary alteration did not address the potential
degradation of the Class IE circuit as a result of the interface.
The
issue was unresolved pending clarification of a March 6, 1985, CECo
commitment (letter from 8. Rybak (CECo) to R. Gilbert, (NRR)) to
incorporate the isolation philosophy of IEEE-384 and Regulatory Guide 1.75
for plant modifications whenever practical.
Subsequently, the NRC
concluded that IEEE 384 should have been considered in the safety
evaluation process.
The failure to consider the probability of an
occurrence of a malfunction of equipment important to safety in the
temporary alterations safety evaluation is considered a violation
(50-237/91016-0l(DRP)) of 10 CFR 50.59.
The root cause of the violation
was a failure of the plant staff to recognize the need to evaluate and
incorporate the requirements of IEEE-384 into the safety evaluation
process.
Following NRC identification of this concern, Dresden Administrative
Procedure (OAP) 10-02,
11 10 CFR 50.59 Reviews Screening and Safety
Evaluation,
11 was revised to incorporate a Safety Evaluation/Screening
Review Worksheet which specifically addressed electrical separation
criteria.
Also, in response to a previous violation (50-237/90022-01) of
10 CFR 50.59, CECo committed to implement a program to rebaseline the
Updated Final Safety Analysis Report (UFSAR).
The rebaseline scope should
include all applicable correspondence associated with the Integrated Plant
Safety Assessment Systematic Evaluation Program (SEP).
The licensee
indicated that the UFSAR would be prepared in accordance with Regulatory
Guide 1.70, "Standard Format and Content of Safety Analysis Reports for
Nuclear Power Plants", Revision 3, which specifically addressed Regulatory
Guide 1.75 electric separation requirements.
This issue was considered to
be of minimum safety significance and the appropriate corrective actions
were completed or planned prior to the end of the inspection period.
'Therefore, a Notice of Violation is not being issued in accordance with
10 CFR 2, Appendix C, Section V.A.
The inspectors have no further
concerns in this area.
(Closed) Unresolved Item (50-237/91010-03(DRP)):
The inspector noted that
several safety-related pressure switches which provided input to the
reactor building ventilation air operated isolation damper/closure logic
4
circuitry for Units 2 and 3 were not included in a periodic calibration
program.
These switches were associated with the following components:
2(3)-1601-21
2(3)~1601-22
2(3)-1601-56
2(3)-1601-60
2(3)-1601-23
2(3)-1601-24
2(3)-1601-63
2(3)-5741A(B)
2(3)-5742A(B)
Drywell Purge Inboard Primary Containment (PC)
Isolation Valve
Drywell Purge Outboard (PC) Isolation Valve
Torus Purge (PC) Isolation Valve
Torus Vent (PC) Isolation Valve
Drywell Vent Inboard (PC) Isolation Valve
Drywell Vent (PC) Outboard Isolation Valve
Drywell SBGT (PC) Isolation Valve
Reactor Building Ventilation System (RBVS)
Secondary Containment Isolation Valve
RBVS Secondary Containment Isolation Valve
UFSAR section 5.2.2.6 indicated that air operated valves, which close for
the normal containment isolation mode, failed closed on loss of motive
force.
Although not specifically mentioned in the UFSAR, this function
also was designed for the RBVS isolation valves, in light of the
importance of valve closure to standby gas treatment system (SGTS)
operability.
The pressure switches provided the closure signal prior to
system pressure becoming sufficiently low such that normal system air
would not close the valve under isolation conditions.
Although these switches did receive periodic functional testing, this
alone would not ensure the absence of accumulated non-conservative
setpoint drift over repeated testing intervals.
The licensee had not
determined a minimum setpoint required to ensure sufficient air pressure
to close the valves, the expected drift over a period of time, or an
acceptable calibration interval.
Finally, the licensee had not performed
an analysis to justify the absence of periodic calibration requirements.
Failure to establish these safety-related devices in the test program for
calibrations is a violation (50-237/91016-02(DRP)) of 10 CFR 50, Appendix 8,
Criterion XI.
The inspectors noted that local flow indication for the Unit 2 emergency
diesel generator cooling water lines, installed by modification
Ml2-2-87-054 to meet a Regulatory Guide (RG) 1.97 commitment was also not
in a periodic calibration program.
The new flowmeter was to be used for
inservice testing (IST) testing measurements because of the difficulty in
utilizing installed instrumentation.
Failure to include this device
within the periodic test program for calibrations is another example of
violation 50-237/91016-2(DRP).
One cited and one non-cited violation and no deviations were identified
in this area.
3.
Licensee Event Reports Followup (90712 and 92700)
Through direct observations, discussions with licensee personnel, and
review of records, the following event reports were reviewed to determine
5
that reportability requirements were fulfilled, immediate corrective
action was accomplished, and corrective action to prevent recurrence had
been accomplished in accordance with Technical Specifications.
(Closed) LER 50-237/91002 - Reactor Head Closure Stud Outside FSAR
Allowables for Material Toughness Due to Unknown Cause.
On
January 16, 1991, with Unit 2 in a refueling outage, the licensee
determined through analysis that a reactor head closure stud replaced
during a previous outage did not meet the material toughness requirements
of the FSAR, Appendix D, paragraph 10.10.
The LER was submitted for any condition that resulted in the plant being
outside the design basis (10 CFR 50.73(a)(2)(ii)(B)).
Not meeting the
material specification for a primary cooling system pressure boundary
represented a principal safety barrier in a unanalyzed condition and
outside the design basis.
Requirements for immediate notifications for
operating reactors, 10 CFR 50.72(b)(2)(i), also required notification
within four hours of any event that, if found while operating, would have
resulted in its principal safety barriers being seriously degraded, or
being in an unanalyzed condition, that significantly compromises plant
safety.
This four hour notification was not made and was considered a
violation (50-237/91016-03(DRP)) of reporting requirements.
Subsequent
licensee engineering analysis, completed on March 22, 1991, concluded
that sufficient structural margin existed for operation of the reactor.
Also, the inspector reviewed the licensee's Deviation reports (DVRs)
generated during the inspection period for potential adverse trends in
personnel and equipment performances.
DVRs were also reviewed for
initiation and disposition as required by the applicable procedures and the
QA manual.
One cited violation and no deviations were identified in this area.
4.
Operational Safety Verification (71707 and 42700)
During the inspection period the inspectors verified daily, and randomly
during back shift and on weekends, that the facility was being operated
in conformance with the licenses and regulatory requirements and that the
licensee's management control system was effectively carrying out its
responsibilities for safe operation.
This was done on a sampling basis
through routine direct observation of activities and equipment, tours of
the facility, interviews and discussions with licensee personnel,
independent verification of safety *system status and limiting conditions
for operation action requirements (LCOs), corrective action, and review
of facility records.
On a sampling basis the inspectors daily verified proper control room
staffing and access, operator behavior, and coordination of plant
activities with ongoing control room operations; verified operator
adherence with the latest revisions of procedures for ongoing activities;
verified operation as required by Technical Specifications (TS);
including compliance with LCOs, with emphasis on engineered safety
6
features (ESF) and ESF electrical alignment and valve positions;
monitored instrumentation recorder traces and duplicate channels for
abnormalities; verified status of various lit annunciators for operator
understanding, off-normal condition, and corrective actions being taken;
examined nuclear instrumentation (NI) and other protection channels for
proper operability; reviewed radiation monitors and stack monitors for
abnormal conditions; verified that onsite and offsite power was available
as required; observed the frequency of plant/control room visits by the
station manager, superintendents, assistant superintendents, and other
managers; and observed the Safety Parameter Display System (SPDS) for
operability.
During tours of accessible areas of the plant, the inspectors made note
of general plant/equipment conditions, including control of activities in
progress (maintenance/surveillance), observation of shift turnovers,
general safety items, etc.
The specific areas observed were:
a.
Engineered Safety Features (ESF) Systems
Accessible portions of ESF systems and components were inspected to
verify:
valve position for proper flow path; proper alignment of
power supply breakers or fuses (if visible) for proper actuation on
an initiating signal; proper removal of power from components if
required by TS or FSAR; and the operability of support systems
essential to system actuation or performance through observation of
instrumentation and/or proper valve alignment.
The inspectors also
visually inspected components for leakage, proper lubrication,
cooling water ~upply, etc.
b.
Radiation Protection Controls
The inspectors verified that workers were following health physics
procedures for dosimetry, protective clothing, frisking, posting,
etc., and randomly examined radiation protection instrumentation for
use, operability, and calibration.
c.
Security
Each week during routine activities or tours, the inspector
monitored the licensee's security program to ensure that observed
actions were being implemented according to their approved security
plan.
The inspector noted that persons within the protected area
displayed proper photo-identification badges and those individuals
requiring escorts were properly escorted.
The inspector also
verified that checked vital areas were locked and alarmed.
d.
Housekeeping and Plant Cleanliness
The inspectors monitored the status of housekeeping and plant
cleanliness for fire protection, prote~tion of safety-related
equipment from intrusion of foreign matter and general protection of
equipment from hazards.
7
e.
Plant Procedure Review
The inspector reviewed approximately 100 temporary changes made to
various procedures and concluded that the corresponding safety
evaluations met the requirements of Dresden Administrative Procedure
(OAP) 10-02,
11 10 CFR 50.59 Review Screening -and Safety Evaluation, 11
OAP 09-06,
11Temporary Changes to Procedures 11 and 10 CFR 50.59.
The
evaluations provided an adequate bases for determining that an
unreviewed safety question did not exist.
The inspectors also monitored various records, such as tagouts, jumpers,
shiftly logs and surve~llances, daily orders, maintenance items, various
chemistry and radiological sampling and analysis, third party review-
results, overtime records, QA and/or QC audit results, and postings -
required per 10 CFR 19.11.
No violations or deviations were identified in this area.
5.
Monthly Maintenance Observation (62703)
Station maintenance activities affecting the safety-related systems and
components listed below were observed/reviewed to ascertain that they
were conducted in accordance with approved procedures, regulatory guides,
and industry codes or standards and in conformance with Technical
Specifications.
The following items were considered during this review:
the Limiting
Conditions for Operation (LCOs) were met while components or systems w~re
removed from service; approyals were obtained prior to initiating- the
work; activities were accomplished using approved procedures and were
inspected as applicable; functional testing and/or calibrations were
performed prior to returning components or systems to service; quality
control records were maintained; activities were accomplished by
qualified personnel; parts and materials _used were properly certified;
radiological controls were implemented; and, fire prevention controls
were implemented.
Work requests were reviewed to determine status of
outstanding jobs and to assure that priority is assigned to
safety-related equipment maintenance which may affect system performance.
The inspectors monitored the licensee's work in progress and verified
that it was being performed in accordance with proper procedures, and
approved work packag~s, that applicable drawing updates were made and/or
planned, and that operator training was conducted in a reasonable period
of time.
The following maintenance activities were observed and reviewed:
Unit 2
Rebuild of Diesel Generator Air Start Motors
125v DC Ground Checking
8
Unit 3
Repair of the 3B LPCI Heat Exchanger Bypass Valve (3-1501-llB)
Repair of the 3C Instrument Air Compressor
No violations or deviations were identified in this area.
6.
Monthly Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications during the inspection period and verified that testing was
performed in accordance with adequate procedures, that test
instrumentation was calibrated, that LCOs were met, that removal and
restoration of the affected components were accomplished, that results
conformed with Technical Specifications and procedure requirements were
reviewed by personnel other than the individual directing the test, and
that any deficiencies identified during the testing were properly
reviewed and resolved by appropriate management personnel.
The inspectors witnessed portions of the following test activities:
Unit 2
DOS 6600-1, Diesel Generator 2/3 Monthly Operability Run
DIS 1500-18, Low Pressure Cooling Injection (LPCI) Monthly Flow
Calibration Surveillance
DOS 1500-2, Quarterly Containment Cooling Service Water Pump Test
for Inservice Test (IST) Program
DOS 1500-3, Containment Cooling Service Water Pump Test
DOS 1500-6, LPCI System Pump Operability Test with Torus Available
DOS 1500-5, LPCI System Quarterly Flow Rate Test
DOS 1500-10, Quarterly LPCI Pump Operability Test with Torus
Available for the IST Program
Unit 3
DOS 6600-1, Diesel Generator 3 Monthly Operability Run
DOS 1400-1, Core Spray Pump 3A Test with Torus Available
DOS 1600-1, Quarterly Valve Timing
DOS 1600-2, Valve Operability Check
DOS-250-1,
Main Steam Isolation Valve (MSIV) 10% Closure
DOS 300-1,
Control Rod Drive Exercise
DOS 500-3,
Average Power Range Monitor (APRM) Rod Block and Scram
Functional Test
DOS 5600-2, Monthly and Weekly Turbine Checks
During the performance of quarterly LPCI and core spray surveillances,
the inspector noted that one Nuclear Station Operator (NSO) was keeping
track of procedural evolutions and data recording in as many as five
procedures at one time.
The inspector identified this complex procedural
matter to the licensee.
The licensee indicated that the matter will be
evaluated for streamlining .
9
While reviewing diesel generator (DIG) surveillance activities, the
inspector questioned the D/G output breaker logic design.
During
conditions when the output breaker was closed~ such as the case during*
full load testing, a DIG overload condition could develop following the
Per the UFSAR, following a LOOP
(undervoltage) condition, the engineered safety features bus feeder
breaker opens, the DIG receives a start signal, and load shedding occurs.
The DIG output breaker closes after the D/G reaches rated speed and
voltage.
If a loss of coolant accident (LOCA) signal was present, the
essential loads would be sequenced on to the bus.
However, if the D/G
output breaker was closed prior to the LOOP, the bus voltage may be
maintained above the undervoltage (UV) relay trip settings.
The added
demand resulting from the connection of non-safety/non-essential loads
would result in an overload condition of the D/G.
If the LOOP condition
was coincident with an accident signal, then the D/G protective devices,
except generator fault and mechanical overspeed, would be disabled.
The
end result could be damage to the D/G units and the total loss of AC
power to .the safety bus.
Current design did not ~rovide for automatic
opening of the D/G output breaker upon a LOCA signal to ensure the initial
undervoltage condition and subsequent load shedding occurs.
During conditions when one of the D/Gs or an offsite pbwer source is
inoperable, Technical Specifications require the operable D/G(s) to be
paralleled to the offsite power system for at least one hour.
In this
case, the Technical Specifications prescribed actions could result in an
increased probability of a station blackout (total loss of AC power).
The
licensee reviewed the concern and concluded that the p~obability of a
spurious accident signal (or design basis event) in conjunction with a
LOOP while all available emergency onsite D/Gs were being operated, was
small.
Also, the licensee considered this scenario reviewed by the NRC
under the SEP.
A review of the General Design Criteria (GDC) 17 Safety Evaluation
Reports (SER) and the Systematic Evaluation Program (SEP) Topic VIII-2,
110nsite Emergency Power Systems (Diesel Generator)
11 indicated system
response, when the D/G output breaker is initially closed,
was not
specifically addressed.
However, Standard Review Plan, Section 8.3.1 and
11 Periodic Testing of Diesel Generator Units Used
as Onsite Electric Power Systems at Nuclear Power Plants
11 , referenced as
review criteria specified that periodic testing of the D/G units should
not impair the capability of the unit to respond to challenges within the
required time. This issue is considered an open item (50-237/91016-04(DRS))
pending on NRC determination of whether the current DIG breaker logic
design is consistent with existing regulations/commitments.
No violations or deviations were identified.
7.
Safety Assessment and Quality Verification (35502 and 40500)
Inspectors were given a presentation by the Onsite Nuclear Safety Group
(ONSG) which included a discussion of activities ongoing within ONSG.
One of these activities included a program entitled
11 Lessons Learned
10
Initial Notification.
11
This program provided subjective information on
significant events at other CECo nuclear plants which would be
disseminated to all the CECo nuclear stations within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of its
occurrence.
Such information provided an enhanced level of awareness for
the remaining faciliti.es, and lowered the probability for recurrence of
the same type event at another nuclear unit.
No violations or deviations were identified in this area.
8.
Events ( 93702)
a.
Between May 16 and May 29, 1991, the Unit 2 circulating water (CW)
inlet temperature indication reflected a value in excess of
95 degrees F.
The inspector asked whether the CW inlet temperature
was representative of the ultimate heat sink temperature available to
the LPCI and DIG heat exchanger following a design basis event due to
the relative locations of the suction sources.
The LPCI and the
dies~l generator heat removal analysis were bounded by 95 F cooling
water.
In a response to the concern, the licensee performed
independent temperature monitoring at the 28 LPCI heat exchanger and
at the crib house to verify actual inlet temperature was less than or
equal to 95 F.
In addition, the results of the special test was used
to reference the screen house temperature recorder to ensure the
design basis temperature limit of 95 degree F is not exceeded in the
future.
b.
On June 9, 1991, a Unit 2 reactor scram occurred from 42 percent
rated thermal power due to high reactor pressure.
The pressure
transient resulted from an unexpected turbine trip while performing
the weekly surveillance on the turbine thrust bearing wear detector.
All turbine bypass valves performed as designed; however, the scram
setpoint was still reached.
During the two minutes between the
turbine trip and reactor scram, control room operators partially
inserted one control rod in an attempt to limit the reactor
power/pressure transient.
The turbine trip resulted from the thrust bearing wear detector
being out of adjustment when the trip setpoint was reached prior to
activation of the bypass testing interlock.
Although data from
earlier steps in the surveillance could have alerted the operators to
a danger of continuing the test, the procedure did not alert the
operators to the signif1cance of this data.
The need for detector
adjustment had been identified in earlier surveillances and a work
request was written, but the work was delayed.
This adjustment was
made following the scram.
The inspector will r~view the licensees' post scram investigation
process and scram report when generated.
c.
On June 13, 1991, during the routine calibration surveillance, two
emergency core cooling system (ECCS) level switches and were found
non-conservatively out of calibration.
These switches were
recalibrated as part of the same procedure.
The switches (one out of
11
two taken twice logic) provided input into the core spray system and
low pressure coolant injection system initiatiori logic.
The two
other switches in the trip system were within tolerance.
The time
of discovery for the out-of-tolerence switches was recorded on the
deviation report as 8:00 p.m. on June 13, 1991.
The SCRE received
the.DVR sometime after the shift turnover (approximately 11:00 p.m.)
and notified the NRC via the Emergency Notification System at
00:52 a.m. on June 14, 1991.
At the time of notification, the licensee believed that the two
out-of-tolerance switches would have resulted in ECCS actuation at
1/2 inch of reactor vessel level below the TS specified setpoint.
Based on this, the ENS call was made as a 24-hour requirement for a
violation of TS as required by the operating license, condition 2.G.
The justification provided on the DVR for classifying the call was
that activation would be 1/2 inch below the setpoint.
Further. review by the licensee found that the actual logic
arrangement ihcluded parallel switches which would have provided the
ECCS actuation within the required level setpoints.
Based on this
information, this event was no longer reportable and the licensee
withdrew the notification call.
Review by the NRC concluded that the event, as interpreted at the
time, would have required a 4-hour notification in accordance with
10 CFR 50.72 (b)(2)(iii)(D) for any condition that alone could have
prevented the safety function of a system needed to mitigate the
consequences of an accident.
Once the operating shift evaluated the
consequences of the out of calibration switches, contact via the ENS
was made in less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
However:
(1)
(2)
(3)
Transmittal of information from the IM staff to the operating
staff was not timely; nor was assessment of the impact such as
the direction or magnitude of the setpoint drift provided in
the DVR.
The operations staff did not appear to have
aggressively pursued the ramifications of the DVR until after
shift turnover.
The operations staff did not accurately assess the implication
of the two switches being out-of-toi'erance.
The SCRE 1 s
knowledge of ECCS logic appeared to be weak.
A sound engineering basis was not provided in classifying this
event as a license condition instead of 10 CFR 50.72.
It
appears that instead of an engineering judgement, a great deal
of discussion was held with plant managers which concluded with
a decision that the condition did not meet a limiting safety
system setpoint as defined in 10 CFR 50.36.
references reportability in accordance with 50.72.
No violations or deviations were identified in this area.
12
Training Effectiveness (41400, 41701)
The effectiveness of training programs for licensed and non-licensed
personnel was reviewed by the inspectors during the witnessing of the
licensee
1 s performance of routine surveillance, maintenance, and
operational activities and during the review of the licensee 1s response
to events which occurred during the inspection period.
Personnel
appeared to be knowledgeable of the tasks being performed, and nothing
was observed which indicated any ineffectiveness of training.
No violations or deviations were identified in this area.
10.
Systematic Evaluation Program Items (92701)
11Safety Evaluation Report Related to the Full-term Operating
License for Dresden Nuclear Power Station, 11 Table 2.1, identified 22 SEP
Integrated Plant Safety Assessment Report (IPSAR) topic resolutions to be
confirmed by the NRC Region III office.
The following item in that report was confirmed as closed by the
inspectors:
Item 6 - Topic VI-4/4.18.6
The completion for Item 2 for Topic II-3.b.l/4.l.4 is being tracked as
Open Item 50-237/89019-04.
The following three items remain to be verified
as closed by the licensee and confirmed by the NRC.
They are tracked
under Open Item (50-237/90027-14(DRP)).
Item 13 - Topic III-2/2.2.2 (Supp. 1)
Item 14 - Topic III-4.A/4.5.3 and 2.2.2 (Supp. 1)
Item 16 - Topic VI-4/4.18.2; Topic VI-6/4.19
Each of these items were in some stage of verification review by the
licensee.
No violations or deviations were identified.
11.
Report Review (90713)
During the inspection period, the inspector reviewed the licensee's
Monthly Operating Report for April 1991.
The inspector confirmed that
the information provided met the requirements of Technical Specification 6.6.A.3 and Regulatory Guide 1.16.
The inspector also reviewed the
Dresden Nuclear Power Station Monthly Plant Status Report for April 1991.
A NRC specialist inspector reviewed the D2R12 IS! report of activities
performed from September 23, 1990 through February 10, 1991, and determined
that the data presented in the !SI report was consist~nt with inspector
observations documented in inspection report 50-237/90024(DRS).
No violation~ or deviations were ide~tified.
13
' *
12.
13.
OQen Items
Open items are matters which have been discussed with the licensee which
will be further reviewed by the inspector and which involved some actions
on the part of the NR~ or licensee or both.
Open items disclosed during
the inspection are discussed in paragraph 6.
Exit Interview
The inspectors met with licensee representatives (denoted in paragraph 1)
during the inspection period and at the conclusion of the inspection
period on June 28, 1991.
The inspectors summarized the scope and results
of the inspection and discussed the likely content of this inspection
report.
The licensee acknowledged the information and did not indicate
that any of the information disclosed during the inspection could be
considered proprietary in nature.
14