ML17199Z138
| ML17199Z138 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 05/25/1988 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| References | |
| 50-237-88-06, 50-237-88-6, 50-249-88-07, 50-249-88-7, NUDOCS 8806100050 | |
| Download: ML17199Z138 (13) | |
See also: IR 05000237/1988006
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos. 50-237/88006(DRP); 50-249/88007(DRP)
Docket Nos. 50-237; 50-249
Licensee:
Commonwealth Edison Company
P. 0. Box 767
Chicago, IL 60690
Facility Name:
Dresden Nuclear Power Station, Units 2 and 3
Inspection At:
Dresden Site, Morris, IL
Inspection Conducted:
March 18 through May 9, 1988
Inspectors:
Approved By:
S. G. Du Pont
P. D. Kaufman
~-:*f-ri2/l~
M. AAfn9,v~~ ~
Reactor Projects Section lB
Inspection Summary
~~s-A~
~
Ins ection durin the eriod of March 18 throu h Ma
9, 1988
e ort
10s. 50-237 88006
P * 50-249 88007 DRP
Areas Inspected: Routine unannounced safety inspection* by the resident
.
inspectors on previous inspection findings; operational safety verification;
followup of events; licensee event reports followup; monthly maintenance
observation; monthly surveillance.observation; refueli~g activities;
verification of Temporary Instructions; SALP meetings; meeting with local
public officials; management meeting; and report review.
Results:
Of the 12 areas inspected, no violations or deviations were
identified in 9 areas; one violation was identified in the area of maintenance
observation (inadequate rigging procedure - Paragraph 5); one violation was
identified in the areas of surveillance observation (failure to follow HPCI
IST surveillance procedure - Paragraph 6). Additionallj, one violation was
also identified in the area of licensee event reports; however, in accordance
with 10 CFR 2, Appendix C, Section V.G.1, a Notice of Violation was not issued
(failure to have required number of instrument channels operable per trip
system - Paragraph 7).
8806100050 880525
ADOCK 05000237
DETAILS
1.
Persons Contacted
Commonwealth Edison Company
- E. Eenigenburg, Station Manager
J. Wujciga, Production Superintendent
- C. Schroeder, Services Superintendent
L. Gerner, Superintendent of Performance Improvement
T. Ciesla, Assistant Superintendent - Planning
- D. Van Pelt, Assistant Superintendent - Maintenance
J. Brunner, Assistant Superintendent - Technical Services
- J. Kotowski, Assistant Superintendent - Operations
R. Christensen, Unit 1 Operating Engineer
G. Smith, Unit 2 Operating Engineer
- E. Armstrong, Regulatory Assurance Supervisor
W. Pietryga, Unit 3 Operating Engineer
J. Achterberg, Technical Staff Supervisor
R. Geier, Q.C. Supervisor
D. Sharper, Waste Systems Engineer
D. Adam, Radiation Chemistry Supervisor
J. Mayer, Station Security Administrator
D. Morey, Chemistry Supervisor
D. Saccomando, Radiation Protection Supervisor
- E. Netzel, Q.A. Superintendent
- R. Stols, Q.A. Engineer
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 personnel, and contract security personnel.
- Denotes those attendina one or more exit interviews conducted on
May 9, 1988 and informally at various times throughout the inspection
period.
2.
Review of Previous Inspection Items (92701)
a.
(Closed) Open Item (237/85015-01):
Local Leak Rate Test (LLRT)
procedure requires revision to incorporate correct methodology
when summing the maximum pathway leakage rate for two valve
isolation systems.
The licensee issued corporate directive
NSDD-S19, Revision 1, dated April 2, 1987, for all stations to
follow and ensure uniformity in the way that ILRT calculations
are performed.
The directive correctly addresses the proper
method to be used when ~ressurizing between two isolation valves
which are tested simultaneously.
The isolation system's leakage
rate is equal to the measured leakage rate.
The licensee is
currently in the process of revising procedure DTS 1600-1, "LLRT
of Containment Isolation Valves", which will incorporate this NSD
directive.
2
b.
(Closed) Open Item (237/85015-02):
ILRT Procedure Revision required
to incorporate correct as-found methodology into Type A test results.
The licensee issued corporate directive NSDD-S19, Revision 1, dated
April 2, 1987, to ensure uniformity in the way that ILRT calcula-
tions are performed.
The directive correctly addresses the proper
methodology to be utilized in calculating the as-found and as-left
Local Leak Rate Test results to determine an as-found Type A test
results.
The licensee is currently in the process of revising
procedure DTS 1600-7,
11Primary Containment ILRT
11
, which will
incorporate this NSD directive.
No violations or deviations were identified in this area.
3.
Operational Safety Verification (71710 and 71707)
The inspectors observed control room operations, reviewed applicable logs
and conducted discussions with control room operators during the period
from March 18 to May 9, 1988.
The inspectors verified the operability of
selected emergency systems, reviewed tagout records and Verified p~oper
return to service of affected components.
Tours of Units 2 and 3 reactor
buildings, refueling floor and turbine buildings were conducted to
observe plant equipment conditions, including potential fire hazards,
fluid leaks, and excessive vibrations and to verify that maintenance
requests h~d been initiated for equipment in need of maintenance.
The inspectors, by observation and direct interview, verified that the
physical security plan was being implemented in accordance with the
-
station security plan.
The inspectors observed plant housekeeping/cleanliness conditions and
verified implementation of radiation protection controls. During the
inspection, the inspectors walked down the accessible portions of
systems to verify operability by comparing system lineup with plant
_drawings, as-built configuration or_present valve lineup lists; observing
equipment conditions that could degrade performance; and verified that
instrumentation was properly valved, fun~tioning, and calibrated.
The inspectors reviewed new procedures and changes to procedures that
were implemented during the inspection period.
The review consisted of
a verification for accuracy, correctness, and compliance with regulatory
requirements.
These reviews and observations were conducted to verify that facility
operations-were in conformance with the requirem~nts established under
technical specifications, 10 CFR, and administrative procedures.
a.
Unit 3 operated continuously for 172 days until March 27, 1988, at
1:58 a.m., when the generator was taken off-line to begin the unit_'s
tenth refueling outage .
b.
Unit 2 exceeded its previous record for days of continuous
operation.
The previous Unit 2 record of 163 days was established
between January 11 and June 21, 1984.
Unit 2 has also passed the
3
recently set station record of 172 days set by Unit 3 in
March, 1988.
The unit continues to operate on day 200 of
continuous operation.
No violations or deviations were identified in this area.
4.
Followup of Events (93702)
During the inspection period, the licensee experienced several events,
some of which required prompt notification of the NRC pursuant to 10 CFR
50.72.
The inspectors pursued the events onsite with 11censee and/or
other NRC officials.
In each case, the inspectors verified that the
notification was correct and timely, if appropriate, that the licensee
was taking prompt and appropriate actions, that activities were conducted
within regulatory requirements and that corrective actions would prevent
future recurrence. The specific events are as follows:
a.
On March 24, 1988, Dresden Units 2 and 3 lost offsite communications
including the ENS, at 4:54 p.m.(CST). *The loss of offsite communiCa-
tions was due to the phone box located approximately 5 miles from the
plant, being struck by an auto.
Internal communications, including
with the.Chicago Load Dispatcher, was maintained. The dispatcher
made the required notification to the NRC via commercial tele-
communications.
All communication networks were returned to
operation at 5:21 p.m.
b.
Unit 3 commenced an orderl~ shutdown at 6:25 p.m., on March 26,
1988, for the planned 10th cycle refueling outage.
The outage is
planned to run through June 26, 1988.
Major activities scheduled to
be performed during the outage include:
Feedwater Regulating Valve
Modifications; LPRM Replacements; SRM/IRM Dry Tube Replacements;
Standby Liquid Control (ATWS) Modification; 250 Volt Battery/Rack
Changeout; Unit 3 and 2/3 Dies~l Generator Stub Shaft ~edification;
and 125 Volt Battery Discharge Test.
As part of the pre-planned shutdown, the licensee elected to take
the High Pressure Coolant Injection system (HPCI) out-of-service
at 6:30 p.m., on March 26, 1988, with Reactor power at 91%, to
perform a HPCI Overspeed Test per Dresden procedure DOS 2300-2.
The purpose is to test the operation of the HPCI turbine overspeed
trip.
The Resident Inspectors and Region III had been previously
informed of this preplanned event on March 24, 1988.
The licensee
made the required ENS call at 6:33 p.m (CST) on March 26, 1988, to
declare the HPCI system inoperable, which put the licensee in a 24
hour LCO Action Statement to be shutdown and Reactor Pressure
reduced to 90 psig. Reactor Pressure was reduced to less than 90
psig at 7:39 a.m., on March 27, 1988, and Reactor Mode switch was
placed to shutdown at 11:37 a.m., the same day ..
c.
During a plant walkdown on December 2, 1987, to followup on
.
discrepancies found during a licensee conducted Quality Assurance
Safety System Functional Inspection (SSFI) oh the Unit 3 Diesel
4
d.
Generator in May 1987, Sargent & Lundy (S&L) identified that the
Starting Air System piping for both Unit 2 and Unit 3 Diesel
Generators was supported from platform handrails inside the diesel
rooms.
S&L informed the licensee at approximately 10:20 a.m., on
March 29, 1988, that the Starting Air System piping did not meet the
FSAR piping design stress requirements.
However, even though the
piping was attached to the handrails, it was analyzed to still be
This piping is utilized to store and deliver sufficient
air to start the diesels under all conditions.
S&L is in the
process of making the required design changes for both units so the
piping will meet FSAR requirements.
On April 7, 1988, at 5:57 p.m.(CDT), with Unit 2 operating at
approximately 92% power, the "2A" Reactor Recirculation pump
tripped.
Control room alarms indicated that the trip occurred from
high differential current which caused a generator lockout. Prior
to the Recirc pump trip, the. "Recirc M/G A Generator Differential
Current High" alarm was continually comirig in and was being
investigated by.the shift.
While attempting to manually control reactor water level, flow and
position indication of the
11 2A" Feedwater Regulating valve indicated
that the valve would not fully close when given a full closed signal
from it's controller. With the valve remaining stuck at 15% open,
reactor level increased to 53 inches before the
11 2A" Feedwater
Regulating valve was isolated from the control room.
Disassembly of.
the 2A Feedwater Regulating valve disclosed the reason for ~he val~e
not going full-close was that two bolts, and a seat assembly hold
down clamp from a Reactor Feedwater Pump Isolation Check Valve, were
found lodged between the plug and seat. Examination of the 2A FRV
stem and plug revealed a crack in the seal weld between the stem and
the plug.
The licensee replaced the stem and the valve was returned
to service at 1:35 a.m., on April 10 9 1988.
In addition, the
licensee has performed testing of all three Reactor Feed Pump (RFP)
Discharge Check Valves and could not verify which check valve the
hold down clamps originated from.
After discussions with the NRC *
Region III Office, the licensee is evalu~ting the situation to
determine whether all three feedwater discharge check valves should.
be disassembled to verify which valve. is operating in a degraded
condition.
The licensee has currently disasembled the "2C RFP
discharge check valve and found no missing hold down.clamps.
The
valve manufacturer (Crane), in addition to licensee personnel from
the Quad Cities Station, were at the Dresden Station to examine the
- "2C" valve and discuss recolTD'Tiendations about the seat assembly hold
down arrangement.
Quad Cities has the same hold down seat assembly
clamps installed in their RFP discharge theck valves. fhe licensee
is presently waiting on the valve manufacturer's resolution prior
to disassembling any more RFP discharge check valves.
5
During the event, reactor water level was maintained by the
11 2B
11
Feedwater Regulating (Drag) valve.
The
11A
11 phase of the
Recirculation M/G set breakers and relays were satisfactorily
tested and some worn brushes on the generator were replaced.
The "2A
11 M/G set was returned to service at 3: 30 a .m., and the
Recirc pump was placed in service at 4:15 a.m., on April 8, 1988.
Unit 2 was increased in reactor power while monitoring the M/G
sets breakers and relays.
On April 14, 1988, the
11 2A
11 Recirc Pump was removed from service
at 5:03 a.m., in order to inspect the current transformer circuits.
A drywell entry was made at approximately 7:30 a.m., and revealed
a loose wire connection on the
11A
11 phase of the current transformer
on the
11 2A
11 Recirc Pump motor.
The licensee promptly repaired the
connection and the Recirc Pump was returned to service at approxi-
mately 12:05 p.m. on April 14, 1988.
e.
With Unit 3 shutdown in a refueling outage, the licensee received
a Group II Isolation at 4:41 a.m.(CDT), on April 12, 1988.
While
hanging an outage tag on Unit 3 Atmosphere Containment Atmosphere
Dilution/Containment Air Monitoring (ACAD/CAM) system a Group II.
Isolation unexpectedly occurred. The Group II Isolation was
apparently caused by loss of power to both Drywell High Radiation
sensors in both logic channels .. All systems functioned as designed.
The Unit 3 Reactor Building ventilation fans tripped, Standby Gas
Treatment system auto-started and all isolation valves, that were
not out-of-service for the refueling outage, closed pertaining to
the Group II isolation signal.
The outage was immediately cleared
and power restored to the Drywell High Radiation Sensors.
The 'Group
II isolation was reset at 4:51 a.m., Re~ctor Building ventilation
returned to normal, Standby Gas Treatment system secured and any
isolation valves required to be open were reopened.
f.
On April 26, 1988, at 7:04 p.m.(CDT), the Unit 2 Reactor Building
Vent automatically tripped on a spurious high radiation indication.
The operators took prompt action* and manually tripped the Unit 3
Reactor Building Vent and the
11A
11 train of Standby Gas Treatment
System operated as required.
The licensee performed a walk down of
the refuel floor and the secondary containment and did not discover
any abnormal indications.
In addition, the instrumentation power
supply was verified to be fully operable.
The Reactor Building Vent
system was returned to service at 7:36 p.m.
The licensee has not
been able to determine the cause of the spurious trip.
g.
With Unit 3 shutdown in a refueling outage, an unplanned Group II
and Group III Isolation occur'red on May 5, 1988, at 8:50 p.m. (CDT).
While taking the Analog Trip System (ATS) panel 2203-73A Division I
out-of-service to perform modification work inside the panel to*
install new reactor pressure and level instruments per modification
M12-3-84-108, an unexpected Group II and Group III Isolations
occurred.
The isolation signals were received when the first fuse
was being removed from the ATS panel.
When the fuse wa~ pulled,
power was lost to the panel. All systems functioned as designed.
6
h.
i.
Unit 3 Reactor Building ventilation fans tripped, Standby Gas
Treatment system auto-started and all isolation valves, that were
not out-of-service for the outage, closed pertaining to the
isolation signals. The outage was immediately cleared, the panel
re-energized, and the Group II and Group III isolation signals were
cleared.
The Reactor Building ventilation system wa~ returned to
norma 1, Standby Gas Treatment system secured at 9: 10 p.m., and any
isolation valves required to be open were reopened.
The licensee
is in the process of reviewing the entire modification package,
including wiring prints and schematic diagrams, to determine the
root cause.
On May 6, 1988, at 8:58 a.m (CDT), the Unit 2 Reactor Building
Ventilation system automatically isolated and the Standby Gas
Treatment system (SBGT) auto-started and operated as intended.
The ESF actuation occurred during post-maintenance testing of the
Unit 2 Reactor Building Vent Radiation Monitor.
The testing was
being conducted on the "B" Channel due to a replaced detector.
When the Health Physics person tripped the
11B
11 Channel to perform
the testing a full trip signal was generated.
Investigation into
cause of the event revealed that procedure DRP 2000-5, utilized to
perform this activity, contained a procedural deficiency.
The
procedure discrepancy resulted in jumpering out the incorrect
terminals for Channel. "A" the Upscale Trip function, instead of
the correct Channel "B" terminals, thus producing the automatic
isolation of the Reactor Building Ventilation system and auto-start
of SBGT.
The Reactor Building Vent system was returned to normal
and SBGT secured at 9:05 a.m.
The licensee issued a temporary
change to procedure DRP 2000-5 correcting the procedural discrepancy.
On May 9, 1988, at 4:30 a.m. (CDT), with reactor power at 72%,
the Unit 2 ~igh Pressure Injection System (HPCI) was declared
inoperable when the HPCI system failed during its scheduled monthly
surveillance.
Cause was attributed to the gland ~eal leak-off
(GSLO) pump which would trip off.shortly after starting. The
licensee determined that the GSLO motor needed to be replaced.
The licensee issued a work request to replace the GSLO motor and
commenced the required Technical Specifications LCO action statement
surveillances. All required surveillances were completed
sat is factor i l y.
No violations or deviations were identified in this area .
. 5. * Monthly Maintenance Observation (62703)
Station maintenance activities of 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 confonnance with technical specifications .
7
The following items were considered during this review:
the limiting
conditions for operation were met while components or systems were
removed from service; approvals 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 determin~ status of
outstanding jobs and to assure that priority is assigned to safety
related equipment maintenance which may affect system performance.
The following maintenance activities were observed/reviewed:
On April 29, 1988, the nonnal primary containment nitrogen makeup
inerting system was rendered inoperable when the liquid nitrogen storage
tank had to be isolated due to a broken 1 1/2 inch nitrogen common header
supply line to both Unit 2 and 3 primary containments.
Unit 3 was in a
refueling outage, and not affected by this event. Unit 2 was operating
at 83% reactor power when a mechanical maintenance person called the
control room to report the broken nitrogen makeup line.
The break
occurred while the mechanical maintenance department was perfonning
rigging activity in the Unit 3 Torus area in preparation for replacing
a valve.
During the rigging of a chain fall, the 1 1/2 inch (copper) nitrogen
makeup line was inadvertently encompassed by the support rigging,
resulting in a break in the normal nitrogen makeup flow path.
The only method of securing the nitrogen leak/break location was to
secure the liquid nitrogen tank; rendering it inoperable.
The licensee
entered Technical Specification 3.0.A., requiring a plant shutdown.
An Unusual Event was declared and the ENS call was made.
The licensee
began reducing power from 83% reactor power down to 66% reactor power*
before the licensee provided an alternate nitrogen makeup flow path to
the primary containment through the nitrogen purge vaporizer line.
The licensee terminated the Unusual Event on the same day, when the
alternate nitrogen flowpath was established. Repairs to the normal
nitrogen makeup line were completed on the same day, and returned to
service.
Further evaluation by the inspectors revealed that the rigging procedures
DMP 5800-3 and OAP 4-4 were insufficient in providing clear established
control requirements on what can be utilized as a support to which
lifting devices and loads can be applied.
The inadequate rigging
instructions is considered a violation of 10 CFR 50, Appendix B,
Criterion V (237/88006-0l(DRP); 249/88007-0l(DRP)).
One violation was identified in this area.
8
6.
Monthly Surveillance Observation (61726)
The inspectors observed surveillance testing required by technical
specifications and verified that testing was performed in accordance
with adequate procedures, that test instrumentation was calibrated,
that limiting conditions for operation were met, that removal and
restoration of the affected components were accomplished, that test
results conformed with technical specifications and procedure require-
ments and 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:
While reviewing the Unit 2 High Pressure Coolant Injection (HPCI)
In-Service Testing (IST) surveillance results on April 4, 1988, the
licensee determined that the HPCI pump discharge flow exceeded the
r~quired Action Range high flow limit of 5325 gpm.
The flow observed
was documented to be 5450 gpm.
Since the pumps IST test results fell
into the Required Action Range the HPCI system was declared inoperable
on April 4, 1988.
The licensee appropriately entered the Technical
Specification LCO action statement, which is a 7 day LCO and made the
required ENS notification.
The licensee commenced testing the other
ECCS systems required by the LCO Action Statement, with the exception
of Core Spray and Low Pressure Coolant Injection systems, which were
successfully tested just prior to the HPCI system being declared
In addition, the licensee proceeded to conduct another
HPCI pump IST surveillance. During this test the HPCI pumps discharge
flow was observed to be 5000 gpm, which is within the IST Acceptable
Range.
Based upon these test results, the HPCI system was declared
Subsequently, upon further review and discussions of the first HPCI
surveillance test, it was discovered that the HPCI system should not
have been declared inoperable.
The licensee determined that the
operator in the control room performing the HPCI IST. surveillance
failed to properly adjust the position of the HPCI Flow Controller
setpoint from 5600 gpm to 5000 gpm pump discharge required by Dresden
Operating Surveillance procedure, DOS 2300-6, "Monthly HPCI System
Pump Test For the In-Service Test (IST) Program.
11
This apparently
caused the pump discharge flow to be in excess of the IST Acceptable
Range.
The licensee made an ENS call on April 5, 1988, retracting the
previous HPCI reportability call declaring HPCI inoperable.
The
licensee concluded that the HPCI system was never inoperable since the
discharge pump flow rate would have fallen within the IST Acceptable
Range if the operator had correctly followed procedure dur1ng the first
IST test.
The failure to adjust the HPCI flow controller to 5000 gpm, in accordance
with approved procedure DOS 2300-6, is a violation of 10 CFR 50,
Appendix B, Criterion V (237/88006-02(DRP)).
9
In addition, examination of the Unit 2 NSO Log Book for the 1500-2300
shift on April 4, 1988, revealed that an entry was made at 1755 hours0.0203 days <br />0.488 hours <br />0.0029 weeks <br />6.677775e-4 months <br />
denoting the completion of DOS 2300-6 surveillance.
However, the Unit 2
NSO Log Book did not contain documentation of the unacceptable HPCI pump
!ST results or the HPCI system being declared inoperable.
Dresden
Administrative Procedure DAP 7-5, "Operating Logs", requires that these
activities be recorded in the Unit Logs.
The residents were informed
that no entry was made because the HPCI system was declared inoperable
after the Unit 2 operator had received a turnover from the subsequent
shift. The Degraded Equipment Log did have an appropriate entry made
declaring the HPCI system inoperable. Also, the Shift Engineers log also
had the appropriate entry.
The residents informed the licensee that
maintaining proper logs, including NSO logs, and procedure adherence
should be reemphasized to the operating staff.
The residents review of this event found several administrative controls
which may have contributed in the operator error; suc*h as performing
several related HPCI surveillances and a recently issued temporary
change (88-2~76) to DOS 2300-6 with new specified pump flow ranges.
In addition, on further examination of Temporary Change 88-2-76, the
inspectors found that Appendix A to DOS 2300-6 contained information
permitting 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> to review and conduct further analysis of IST test
data if it fell outside the Acceptable Range.
This is contrary to the
NRC's position, which was transmitted to all Region III licensees on
September 4, 1987, by Mr~ A. Bert Davis.
The NRC does not allow any
time for analysis to determine whether the component can be considered
operable if the !ST test data falls into the Required Action Range.
The inspectors reviewed a memorandum from the Assistant Superintendent
of Operations, dated October 1, 1987, which delineated the NRC's policy
regarding entry into an LCO based on !ST surveillance results, which are
in the Required Action Range.
The licensee plans to incorporate this
change into the next revision of DOS 2300-6.
One violation was identified in this area.
7.
Licensee Event Reports Followup (90712)
.
. .
Through direct observations, discussions with licensee personnel, and
review of records, the following event reports were reviewed to determine
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 249/88005-00:
HPCI System Intentionally Made
Inoperable to Facilitate Pre-Planned Preventive Maintenance Testing.
The HPCI system was made intentionally inoperable at 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br /> on
March 26, 1988, to facilitate performance of Dresden Operating
Surveillance (DOS) 2300-2,
11HPCI Overspeed Test".
In order to.
conduct the overspeed test the HPCI turbine must be uncoupled from
its driver equipment.
This testing was performed in a controlled
and pre-planned manner while Unit 3 was being shutdown for its
scheduled 10th cycle refueling outage.
10
. *
I
(Closed) LER 249/88006-00:
HPCI Areas Temperature Switches Exceeded
Technical Specification Limit Due to Instrument Setpoint Drift.
As part of the Unit 3 refueling outage surveillance testing was
performed on the HPCI Area temperature switches per Dresden
Instrument Surveillance (DIS) 2300-7. A total of 16 temperature
switches are located in four different areas of the HPCI pump room.
The switches are connected in four one-out-of-two-twice logic
channels.
There are two trip systems for the HPCI auto-isolation
system.
These tempe0ature switches are required to trip at less
than or equal to 290 F.
The as-found trip settings of 7 switches
were above the 200 F Technical Specification (TS) limit of Table
3.2.1. This TS table also states that four instrument channels
shall be operable per trip system. This requirement was not met
since only three instrument channels were operable. Temperature
switches 3-2370D and 3-2371D failed, resulting in the lOlD relay
being inoperable.
The failure to have the required number of instrument channels
operable per trip system is a violation of Technical Specification
Table 3.2.1. (249/88007-02(DRP)). This violation meets the tests
of 10 CFR 2, Appendix C, Section V.G.1; consequently, no Notice of
Violation will be issued and this matter is considered closed.
As corrective actions for this event the licensee has: recalibr5ted
all th0 temperature switches to within the station limit of 170 F
to 185 F; given Impell Corporation the authorization to search for
a suitable replacement switch per Action Item Report No.12-86-46
(249-200-88-03001); accelerated calibration frequency in order to
determine the optimum calibration frequency and inspection interval;
2 switches will be inspected (1) month following the Unit 3 -startup
from the 1988 refueling outage scheduled to be completed June 26,
1988, and two temperature switches from Unit 2 HPCI pump room will
be tested during a May 1988 maintenance outage to evaluate whether
an accelerated calibration frequency is required for Unit 2.*
Additionally, the licensee's industry~wide NPRDS search on the
United Electric Controls Company temperature switches revealed that
the unreliability of these switches has been limited to the Dresden
Station.
Of the 16 reported failures, 12 have been attributed to
setpoint drift.
One violation was identified in this area.
The violation met the
criteria.of 10 CFR 2, Appendix C and no Notice of Violation was issued.
8.
Refueling Activities (86700)
The inspectors witnessed several shifts of fuel handling operations while
the Unit 3 fuel assemblies were being unloaded from the reactor vessel
to the spent fuel pool. All 724 fuel bundles were unloaded from the
core between April 2 and April 7, 1988, which met the licensees outage
schedule.
The observed acti~ities were verified to be in accordance
with station procedures and Technical Specifications.
11
During an inspection of these activities, the inspectors witnessed a
cont~act person, who had been performing ISi work on the reactor vessel
head, make an error with respect to not removing the rubber outer foot
wear prior to proceeding to the next step-off pad.
The licensee's fuel
handling foreman observed this event and took prompt effective corrective
action to curtail any possible further spread of contamination.
The
individual was specifically counselled by the foreman.
In addition, the
licensee stopped all ISI work on the reactor vessel head and provided
those individuals with further Radiation Protection guidance and training
the following day.
The resident inspectors view this event as a positive
trend by management and first line supervision involvement to assure
quality. *
Additionally, the licensee has i.ncreased usage of mock-ups, including a
model of the drywell and internals to reduce the man-rem dosage.
No violations or deviations were identified in this area.
9.
Verification of Multi-Plant Actions (Temporary Instruction 2515/93)
The inspectors verified by review of audit and surveillance docum~ntation
review that the licensee had adequately implemented the January 1980
Office of N~clear Reactor Regulation (NRR) request for licensees to
include Diesel Generator (DGJ fuel oil in their Quality Assurance (QA)
programs.
The review revealed that Dresden's QA Department performed both onsite
and offsite QA audits of DG fuel oil samples and analysis, receipt
inspections and active witnessing of fuel oil sampling .. The QA program
includes DG fuel oil as commercial purchased with safety related
standards which requires verification and analysis of receipt and
storage of DG fuel oil.
10.
SALP Meeting
The NRC met with the licensee at a public meeting at the Dresden facility
on May .2, 1988, to discuss the most recent Dresden Systematic Assessment
of Licensee Performance (SALP) 7 Board Report for the Dresden Nuclear
Plant covering the period January 1, 1987 through January 31, 1988.
11.
Management Meeting (30702)
On April 19, 1988, a meeting was held at the NRC, Region III office in
Glen Ellyn, Illinois. The meeting was between NRC and CECo Corporate and
Station Management to discuss Dresden Station Performance Improvement
results and receive NRC feedback.
12
12.
Meeting With Local Public Officials (94600)
On May 2, 1988, the residents, members from the region and NRR met with
officials of Grundy County, including the Director of Emergency Services
and the Mayor of Coal City.
The purpose was to discuss the recent SALP
ratings, SALP process and the purpose of the resident inspectors.
13.
Report Review (90712)
During the inspection period, the inspectors reviewed the licensee's
Monthly Operating Report for March and April 1988.
The inspectors
confirmed that the information provided met the requirements of
Technical Specification 6.6.A.3 and Regulatory Guide 1.16.
14.
Viblations For Which a "Notice of Violation" Will Not Be Issued
The NRC uses the Notice of Violation as a standard method for fonnalizing
the existence of a violation of a legally binding requirement.
However,
because the NRC wants to encourage and support a licensee's_ initiatives
for self-identification and correction of problems, the NRC will not
generally issue a Notice of Violation for a violation that meets the
tests of 10 CFR 2, Appendix C, Section V.G.1.
These tests area:
(1) the
violation was identified by the licensee; (2) the violation would be
categorized as Severity Level IV or V; (3) the violation was reported to
the NRC, if required; (4) the violation will be corrected, including
measures to prevent recurrence, within a reasonable time period; and (5)
it was not a violation that could reasonably be expected to have been
prevented by the licensee's corrective action for a previous violation.
A violation of regulatory requirements identified during the inspection
for which a Notice of Violation will not be issued is discussed in
paragraph 7.
15.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on May 9, 1988, and infonnally throughout the inspection period, and
summarized the scope and findings of the inspection activities.
The inspectors also discussed the likely informational content of the
inspection report with regard to documents or processes reviewed by the
inspector during the inspection.
The licensee did not identify any such
documents/processes as proprietary.
The licensee acknowledged the
findings of the inspection.
13