ML17191A900
| ML17191A900 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 09/24/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17191A898 | List: |
| References | |
| 50-237-98-21, 50-249-98-21, NUDOCS 9810020067 | |
| Download: ML17191A900 (30) | |
See also: IR 05000237/1998021
Text
U.S. NUCLEAR REGULA TORY COMMISSION
REGION 111
Docket Nos:
License Nos:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9810020067 980924
ADOCK 05000237
a
. 50-237; 50-249
50-237/98021 (DRP); 50-249/98021 (DRP)
Commonwealth Edison Company
Dresden Nuclear Station, Units 2 and 3
6500 North Dresden Road
Morris, IL 60450
July 14 through August 25, 1998
K. Riemer, Senior Resident Inspector
D. Roth, Resident Inspector
B. Dickson, Resident Inspector
C. Brown, Reactor Engineer, Riii
P. Lougheed, Reactor Engineer, Riii
R. Langstaff, Reactor Engineer, Riii
R. Lerch, Project Engineer, Branch 1 Riii
G. O'Dwyer, Reactor Engineer, Riii
M. Ring, Chief
Reactor Projects Branch 1
EXECUTIVE SUMMARY
Dresden Nuclear Station Units 2 and 3
NRC Inspection Report 50-237/98021(DRP); 50-249/98021(DRP)
This inspection included routine resident inspection from July 14, 1998, through
August 25, 1998, augmented by regional inspectors.
This inspection also included aspects of licensee operations, engineering, maintenance, and
plant support, and included reviews of miscellaneous inspection followup items by regional
inspectors.
Operations
The licensee planned power change evolutions well and executed troubleshooting
activities in accordance with the plans. Operators performed the evolutions in a
deliberate and controlled manner (Section 01.2) ...
The licensee declared the Unit 2 HPCI system inoperable during this inspection period
due to the failure of the trip solenoid valve. The symptoms of this failure were similar to
an earlier failure (Section 02.1 ).
Routine performance was generally acceptable (Section 04.1).
During this inspection period, the operators violated Technical Specifications during
movement of spent fuel. The failure to recognize entry conditions and action
- statements of the Technical Specifications continued a negative trend (Section 04.2).
Maintenance
The inspectors identified no concerns with jobs directly observed (Section M1 .1).
Material condition issues continued-to adversely affect plant operations. Some of these
issues represented rework for the maintenance organization (Section M2.1).
The inspectors noted discrepancies between .administrative and procedural
requirements for independent verification. The licensee's Nuclear Oversight group also
identified this issue and was pursuing it through the corrective action process
(Section M3.1).
Failure to execute procedures correctly resulted in the generation of an unexpected
half-scram and disabled part of a reactor core protective feature. Independent
verification, as implemented in this case, failed to prevent the error (Section M4.1),
Poor work practices on the refuel floor presented an unnecessary challenge to control
room operators (Section M4.2).
2
Engineering
The repetitiveness of several items indicated that corrective actions had not always
been effective at eliminating the concerns (Section E1 .1).
Plant Support
Breakdowns in licensee processes and practices resulted in the release of
contaminated soil from the site (Section R4.1).
3
Report Details
Summary of Plant Status
Unit 2 began this inspection period at full power. On August 6, 1998, the generator was taken
off line to address a generator ground problem. The problem was addressed, the generator
placed back on line and near-full power restored by August 10, 1998. Return to full power was
delayed until August 13, 1998, due to a moisture separator high level alarm. After the alarm
was addressed, the unit returned to and remained at full power for the remainder of the
inspection period.
Unit 3 remained at full power throughout the inspection period, except for small decreases to
support maintenance and surveillance testing.
Full power c;m both units was limited by the maximum steam flow allowed by the analysis for an
anticipated transient without scram (A TWS) event. The licensee had not completed actions to
remove the limit during this period.
I. Operations
01
Conduct of Operations
01.1
General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of.
ongoing plant operations. Specific events and noteworthy observations are detailed in
the sections below.
During the inspection period, some events occurred for which the licensee was required
by 10 CFR 50.72 to notify the NRC. The events and notification dates are listed below:
07/30/98
08102198
(Unit 2) High pressure coolant injection (HPCI) system
declared inoperable due to the inability to trip the turbine
using the remote turbine trip push-button during
operability surveillance testing.
(Unit 2) Partial Group I isolation caused by blown
, fuse while changing main control room main steam
isolation valve*(MSIV) light indication. The
licensee subsequently retracted this notification.
4
01.2 Down Power Evolutions in Support of Troubleshooting Activities (Unit 2)
a.
Inspection Scope (71707)
The licensee performed two downpower evolutions to support troubleshooting activities
associated with Unit 2. The inspectors reviewed licensee preparations for the down
power evolutions and observed operators' performance of the unit power
manipulations.
b.
Observations and Findings
Intermittent Generator Field Grounds
Over several weeks, Unit 2 experienced many, intermittent main generator/exciter
ground alarms in the main control room. The alarms were of short duration and cleared
themselves with no operator action. The frequency of the alarm occurrence increased
. to the extent that the alarms were being received every several minutes.
On August 6, 1998, the licensee decreased reactor power to approximately 25 percent*
to 35 percent to facilitate the installation of temporary monitoring equipment to aid in
troubleshooting of the ground location. The licensee, with General Electric assistance,
evaluated the data results to determine an appropriate permanent repair. The licensee
took the main generator off-line August 8, 1998, to perform minor cleaning and
refurbishment activities on the main generator and exciter. During the cleaning and
inspection activities, electrical maintenance personnel discovered the source of the
ground. The insulation on a cable inside the generator exciter housing had chafed
against a support and worn away which allowed the conductor to contact ground. The
licensee repaired the cable and returned the unit to service on August 9, 1998.
Operators properly performed the power change evolutions in accordance with station
procedures. The control room atmosphere was professional and management
exercised good overall control throughout the maintenance activities. The outage was
also well planned and executed from a maintenance perspective.
Moisture Separator Drain Tank Hi Level Alarm
The Unit 2 operators received a moisture separator high level alarm during power
ascension activities following the downpower for troubleshooting and repair of the main
generator ground. An automatic turbine trip and reactor trip occurs approximately
4 inches above the alarm setpoint. Operators lowered reactor power to clear the alarm.
The licensee developed a troubleshooting plan which entailed temporarily disabling the
high level trip to troubleshoot the causes of the alarm. The plant operations review
committee (PORC) aggressively reviewed the proposed plans and rejected the initial
proposal to troubleshoot the concern. Plant staff revised the package to address the
PORC concerns and presented the package to the PORC again. F:ollowing PORC
approval of the revised plans, the licensee attempted to re-create the alarm condition
5
c.
and eliminate the alarm. The licensee was unable to re-create the high level alarm and
operators returned the unit to full power. The alarm did not actuate in again during the
inspection period.
Conclusions
The licensee planned the power change evolutions well and executed the
troubleshooting activities in accordance with.established plans. Operators performed
the downpower evolutions in a deliberate and controlled manner.
02
Operational Status of Facilities and Equipment
02.1
High Pressure Coolant Injection (HPCI) System
a.
Inspection Scope (71707)
b.
The inspectors reviewed the status of the Unit 2 HPCI system.
Observations and Findings
On July 30, 1998, the licensee performed the quarterly operability surveillance for the
Unit 2 HPCI system. During the test, the HPCI system's turbine stop valve failed to
close when an operator depressed the remote turbine trip push button. The licensee
declared the Unit 2 HPCI system inoperable.
During troubleshooting, the licensee identified that.soldering for leads from the HPCI
turbine trip solenoid to the 125 VDC circuit had failed. The termination points for these
leads were inside the body of the trip solenoid. After the licensee resoldered the leads,
the licensee tested the HPCI system turbine stop valve successfully.
The licensee had previously declared the Unit 2 HPCI system inoperable on April 17,
, 1998, due to the inability to trip the HPCI turbine using the remote push-button. Then,
a licensee investigation concluded that the contacts used to connect the 125 VDC
circuit to the HPCI turbine trip solenoid valve were faulty due to corrosion. Thb licensee
suspected that the corrosion caused a momentary loss of continuity across the circuit.
As corrective action, the contacts were cleaned.
This July 1998 event was similar to the April 1998 HPCI failure in that the material
condition of the HPCI trip system caused the licensee to declare the HPCI system
c.
Conclusions
The lrcensee declared the Unit 2 HPCI system inoperable during this inspection period
due to the failure of the. trip solenoid valve. This failure was similar to an earlier failure
that caused the licensee to declare the HPCI system inoperable .
6
04
Operator Knowledge and Performance
04.1
Routine Operations (Units 2. 3)
'
a.
Inspection Scope (71707)
The inspectors observed control room and field activities and compared operator
performances with the licensee's standards and procedures.
b.
Observations and Findings
Usually, the operators performed their assignments satisfactorily. Turnovers were
informative. The operators were aware of plant conditions and equipment status and
could readily answer questions about plant performance.
However, the inspectors noted instances where operator performance was lacking,
including an example where a nuclear station operator (NSO) performed an inadequate
independent verification of a relay jumper connection. This example is discussed in
Section M4.1 of this report; the remaining examples follow~
Inadvertent Manual Start of 3C Low Pressure Coolant Injection (LPCI} Pump
On August 8, 1998, maintenance personnel were inspecting and troubleshooting the
3C containment cooling service water (CCSW) pump. As part of the troubleshooting
effort, maintenance personnel requested that operations staff start the pump so the
packing could be adjusted as needed.
After a review of the appropriate procedures for starting the 3C CCSW pump, an NSO *
proceeded with actions to start the pump. At this point, the NSO .took control of the
wrong control switch and inadvertently started the 3C LPCI pump. The NSO
immediately recognized the incorrect pump start and secured the LPCI pump.
A licensee investigation concluded that the inadvertent CCSW pump start was due in
part to two reasons: 1) Unawareness. An insufficient degree of attention was applied
to the task, and 2) Mindset. A frequently performed task (starting a pump) was not
completely reviewed for expected actions. The licensee also concluded that the NSO
did not give others an opportunity to peer check actions to be taken and review the
control switch to be manipulated.
In Inspection Report (IR) 98019, Section 04.1, the inspectors noted a lack of consistent
self-checking or peer review during control panel manipulations. Self-check and
- solicitation of peers are suggested standards in Dresden Administrative Procedure
(DAP) 05-45, "Operations Standards."
This event emphasized the importance of self-checking and the solicitation of peer
review when performing manipulations on the control panel.
7
c.
Unrecognized Emergency Lighting Dresden Administrative Technical Requirement
(DATR) Limiting Condition of Operation (LCO) .
On July 28, 1998, the licensee identified that operators failed to enter the appropriate
DA TR LCO for safe shutdown lighting when maintenance personnel disabled lighting
circuits 354 and 355 for battery discharge testing. The DA TR LCO limitations were not
exceeded, however, this represented another example where operating personnel
failed to recognize entry into an LCO. In addition, operations staff failed to recognize
that the ongoing maintenance work was unauthorized when originally contacted by
maintenance personnel.
Conclusions
Routine performance was generally acceptable. However, instances occurred where
operator performance was lacking, including a wrong component manipulation and an
example of operator lack of awareness of a DA TR LCO condition.
04.2
Unrecognized Entries into LCO
a.
Scope
On August 6, 1998, operators missed required entries into Technical Specification (TS}
LCOs for suppression chamber and drywell spray (TS 3.7.L} and suppression pool
cooling (3.7.M}. The inspectors reviewed the circumstances associated with the
operators' lack of recognition of the required TS LCO entry conditions.
b.
Observations and Findings
Failure to Recognize Entry into LCO Conditions
On August 6, 1998, operators entered a 4-hour LCO per TS 3.7.D (Primary
Containment Isolation Valves} to support testing of the M03-15Q1..;5D, 3D low pressure *
coolant injection (LPCI} suction valve. Maintenance department personnel were unable
to complete the testing activities successfully and return the valve tQ an operable status
within the 4-hour period. Operators shut the 3-1501-338, (LPCI Division II, manual
suction isolation valve} to comply with the primary containment isolation requirements
of TS 3.7.D. Upon shutting the 338 valve, operators appropriately entered TS 3.5 for
an inoperable LPCI subsystem. However, operators failed to recognize two additional
TS LCO entry conditions. With an inoperable LPCI subsystem, operators should also
have entered TS 3.7.L, for suppression chamber and drywell .spray and TS 3.7.M for
suppression fuel cooling. All of the required TS were 7-day LCOs. The subsequent
two operating shifts also missed the required TS LCO entry conditions.
The following morning, a Station Nuclear Oversight individual reviewed problem
identification forms from the previous day and questioned whether the operators had
identified all appropriate TS LCO entry conditions. Following conversations among
station personnel, operations correctly entered the additional TS LCOs and dated the
8
entries to the original time of equipment inoperability. The station documented the
occurrence via problem identification form 01998-04696, initiated a Prompt
Investigation into the matter, and incorporated the event into a prior trend investigation
report (Investigation 237-230-98-00800, Adverse Trend in LCO Management).
The licensee did not exceed the times specified in the LCOs for suppression chamber
and drywall spray or suppression pool cooling. Therefore, the licensee did not violate
the applicable TS. However, the failure to recognize the required entry conditions
continued an adverse trend, first documented in IR 50-237/249-98019. Inspection
Report 50-237/249-98019 documented the issue in a noncited violation for two
examples of failing to recognize TS LCO entry conditions. Licensee actions taken in
response to the prior occurrences were not effective in preventing another occurrence
of operators failing to recognize TS LCO entry conditions.
,
The failure to recognize and log entries into the two LCOs violated the administrative .
requirements of the TS. Dresqen TS 6.8.A, stated, "Written procedures shall be
established, implemented, and maintained covering the activities referenced below:
1. The applicable procedures recommended in Appendix A, of Regulatory Guide 1.33,
Revision 2, February 1978." Appendix A of Regulatory Guide 1. 33 recommended
administrative procedures for log entries. Dresden Administrative Procedure
(OAP) 07-25, "Operating Charts, Logs and Records," Revision 27, Step E.2., stated,
"The following outlines the requirements for log keeping: .... c.(4) If any activity results
in an LCO condition, the Tech Spec and the applicable actions shall be clearly
identified."
- Contrary to the apove, operators failed to identify the entry into the LCO conditions for
suppression chamber and drywell spray, and failed to identify the entry into the LCO for
suppression pool cooling. However, the NRC refrained from issuing a violatior:i in this
case because the issue of recognition of TS LCO entry conditions was identified as a
noncited violation in Inspection Report 98019 and corrective actions may not have had
sufficient time to be fully effective. The inspectors noted that during this inspection
. period, there were three issues related to recognition of entry into TS (see
Section 04. 1 ). These examples continued an adverse trend first documented in the
prior inspection report.
Failure to Comply With Control Room Emergency Ventilation System TSs
On August 20, 1998, operators violated the requirements ofTS 3.8.D (control room
emergency ventilation system) by granting permission to perform a fuel bundle move .
while the refrigeration control unit (RCU) was inoperable. The inspectors reviewed the
circumstances associated with the event.
On August 20, 1998, operators established an out-of-service to support repair of the
control room RCU service water inlet valve. The repair was an emergent item due to
increased valve leakage; as a result, the licensee changed the work schedule. The
hanging of the out-of-service tags rendered the RCU inoperable and operators
9
c.
appropriately entered TS 3.8.D for an inoperable RCU. The work schedule already
contained an item to move a damaged fuel bundle from the spent fuel pool to the fuel
prep machine to support inspections on the bundle.
While operators correctly recognized that an inoperable RCU required entry into
TS 3.8.D, they did not realize all of the requirements of the TS, and, so, failed to
comply with the TS. While in OPERATIONAL MODE 1, 2, or 3, an inoperable RCU
resulted in a 30-day LCO. This was the part of the TS that the operators recognized.
However, the TS is also applicable to mode "*" which applies, "When handling
irradiated fuel in the secondary containment, during CORE ALTERATION(s), and
operations with a potential for draining the reactor vessel." The TS states that while in
OPERATIONAL MODE"*" with an inoperable RCU, immediately suspend Core
Alteration(s), handling of irradiated fuel in the secondary containment and operations
with. a potential to drain the reactor vessel. When refuel floor personnel moved the
damaged fuel bundle, after receiving control room permission, the licensee violated the
requirements of TS 3.8.D.
The station missed multiple opportunities to prevent the error. The operators who
reviewed the work package and associated out-of-service on the shift before
commencing work failed to catch the conflict between the scheduled fuel move and the
emergent valve repairs. The operators who established the out-of-service and granted
permission to perform the fuel move, repeated that failure. A heightened level of
awareness briefing conducted before the fuel bundle move did not contain complete
discussion concerning TS requirements. The fuel handling supervisor, licensed as a
senior reactor operator limited to fuel handling (SRO-L), also failed to understand the
TS requirements. The violation of TS requirements went undiscovered for 1 day. On
August 21, 1998, fuel handling personnel requested permission to resume movement
of the fuel bundle. A different unit supervisor was on the shift that day and recognized
the conflict between fuel movements and an inoperable RCU. Based on discussions
with the fuel handling supervisor, the unit supervisor. realized that the licensee violated
TS 3.8.D the previous day. The licensee documented the TS violation via problem
identification form 01998-04845 and initiated a prompt investigation to learn the cause
and proper corrective actions.
Dresden TS 3.8.D, stated that when in OPERATIONAL MODE "*"with an inoperable
RCU, "immediately suspend CORE AL TERATION(s), handling of irradiated fuel in the
secondary containment, and operations with a potential for draining the reactor vessel."
Contrary to the above, on August 20, 1998, the licensee moved an irradiated fuel
bundle in the secondary containment while an RCU was inoperable. This action was a
violation of TS 3.8.D (VIO 50-249-98021-01(DRP)).
Conclusions
Operator failures to recognize applicable TS LCO entry conditions and action statement
requirements continued a negative trend first documented in the prior NRC inspection
report (IR 50-237/249-98019(DRP)). The licensee's immediate corrective actions were
ineffective in stopping the trend. Of concern was the fact that the operations
department did not identify all of the TS discrepancies. The prior inspection report
10
08
08.1
08.2
documented examples where the operators demonstrated a lack of recognition of TS
LCO entry conditions; however, the licensee did not violate the TS requirements .
themselves. During this inspection period, one instance of operator non-recognition of
TS entry conditions resulted in a violation of the actual TS requirements.
Miscellaneous Operations Issues
{Closed) Inspection Follow-up Item 50-237/249-95009-02: Out of Service and
Equipment Configuration Control Problems. Beyond immediate corrective actions such
as comprehensive plant walkdowns and trend reviews, the licensee implemented more
rigorous controls on plant work and manipulation of equipment. While some
configuration control problems still exist, they are better tracked and reviewed as part of
routine resident core inspections. This item is closed.
{Closed) Licensee Event Report CLER) 237/90002-02: Reactor Scram Following
Condensate/Condensate Booster Pump Failure Due to Internal Failure. Revision 2 of
the LER was issued October 6, 1995, to clarify methods used to perform 4KV motor
insulation testing. The NRC has reviewed and closed the previous revisions of this
LER. The inspector had no concerns or questions regarding the additional information
provided This item is closed.
08.3
{Closed) LER 237/95006-00: TIP System Isolation Does not Have "Seal in" Logic on
Group II Isolation. The licensee reviewed the licensing basis and concluded that the
requirement for seal-in protection was not clear; however, the licensee modified the
system to add the seal-in logic function so that the TIP system isolation valves will not
automatically reopen when a Group II isolation signal is reset. This item is closed.
08.4
{Closed) LER 249/95-001-01: Scram From Main Turbine Stop Valve Closure Due to
Moisture Separator Level High High
Revision 1 to this LER modified the corrective action for the engineering department to
include training on the Stop, Think, Act and Review process. This item is closed.
08.5
{Closed) LER 249/95008-01: Unit 3 Scram From Main Turbine Stop Valve Closure Due
. to Turbine Trip on High Vibration Caused by Out of Specification Turbine Blade
Material. The licensee performed a thorough review of the reactor scram and plant
performance. The licensee adequately addressed the problems as evidenced by no
subsequent problems related to the scram. This item is closed.
08.6
{Closed) LER 249/95010-00: Inadequate LCO Entry Due to Inadequate Control of
Decay Heat During Cooldown. The operations staff failed to control reactor pressure
when too many steam loads were secured during a cooldown. Pressure increased to
greater than 150 psi and operations personnel had already taken the isolation
. condenser out-of-service. This resulted in the plant being in an unplanned limiting
condition for operation. The inspectors concluded that the licensee's corrective actions
were effective. Operations personnel performance with respect to control of plant
transients has improved. Inspection of plant operations will continue as part of the core
inspection program. This item is closed .
11
08.7
(Closed) LER 237/95013-00: Inadequate Sampling of Service Water Effluent Due to
Use of a Superseded Procedure and Recent System Configuration Change. The
inspectors concluded that the licensee's corrective actions of revising procedure
controls and retraining equipment attendants were adequate. The samples taken *
before, during, and after the problem were acceptable. This issue was of minor
significance, which would not be subject to formal enforcement action in accordance
with NUREG 1600, Rev. 1. This item is closed.
08.8
(Closed) LER 237195015-00 and 01: Leakage Limit Exceeded Due to Excessive
Leakage Past Main Steam Isolation Valves. The licensee refurbished two main steam
isolation valves. Refurbishment of the remaining valves is dependent upon leak rate
test results. Test results have improved due to better maintenance of the seating
surfaces. The licensee reported the failure of two additional valves in LER 237 /98004
and a supplement to the LER will provide the causes and corrective actions when the
licensee determines them. This item is closed.
08.9
(Closed) LER 237/95017-00: Containment Cooling Service Water Vault Penetration
Seals Failed Leak Test Due to Being Out of Adjustment. The licensee attributed this
problem to new seals. Tightening the seal connectors corrected the leakage.
Corrective action was to increase the testing frequency when the licensee installs new
seals. The leakage identified was very small; therefore, this event was of minor
significance, which would not be subject to formal enforcement action in accordance
with NUREG 1600, Rev 1. This item is closed.
08.10 (Closed) LERs 237/97013-00. 237/97014-00. 249/97014-00. 249/98001-00,
249/98002-00, and 237/98009-00: High Pressure Coolant Injection System Inoperable
Due to Gland Seal Leakoff (GSLO) Condenser Level Control Malfunction.
On several occasions the licensee declared the Unit 3 HPCI system inoperable due to
the failure of the GSLO condenser level co*ntrol switch to control level in the GSLO
condenser hotwell automatically. To remedy this, the licensee has completed several
. corrective actions to alleviate this reoccurring problem. One example included a design
change of the type of level control switch used in the GSLO condenser. The original
,
design used a float-type mechanism which consisted of mechanical linkages. The
newer design consisted of electromagnetic contacts which should be more reliable.
Since February 1998, with only one exception (May 4, 1998, Reference LER 98009),
the licensee has successfully completed several performances of Dresden Operating
Surveillance (DOS) 2300-09, "HPCI Gland Seal Leak Off Drain Pump and Condenser
Hotwell Level Control Function Test." Initially, these tests were performed weekly.
Presently, the licensee is performing this test monthly.
The inspectors will continue to follow this issue through routine inspection efforts ..
These items are closed .
12
II. Maintenance
M1
Conduct of Maintenance
M1 .1
General Comments
The inspectors monitored routine maintenance activities through direct observation,
attendance at maintenance and operations meetings, and by reviewing the results of
maintenance.
The inspectors identified no concerns with jobs directly observed. The mechanics and
technicians followed their procedures and work instructions, and correctly documented
the results. Inspectors routine review of issues identified in problem identification forms
(PIFs} revealed some issues in rework and work planning and scheduling, however,
these issues were not safety significant.
Nonetheless, as described in Section M2.1 of this report, the material condition of the
plant significantly challenged smooth full-power operations.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
Maintenance and Availability of Equipment
a.
Inspection Scope (62707)
The inspectors reviewed the licensee's response to some self-revealing events in which
safety-related equipment w~s made unavailable after maintenance, or could not be
restored to operable following maintenance.
b.
Observations and Findings
The inspectors noted that several material condition issues and self-revealing
equipment failures during the inspection period required plant personnel to take prompt
action. The inspectors reviewed the failures to determine the effect on plant safety.
Control Rod Drive (CRD) H-12
On August 12, 1998, 20 minutes after insertion from Position 12 to Position 10 for flow
control line adjustments on Unit 2, CRD H-12 drifted back out of the reactor core to
- Position 12. The event was identified after the operators received a ROD DRIFT
annunciation in the control room. The licensee performed a prompt investigation to
figure out the cause of the control rod drift. The investigation concluded after a review
of operator actions and procedures that human performance or procedural issues did
not cause this event. The CRD system engineer contacted the CRD expert from
General Electric Company for assistance during this investigation; there were two
hypothetical possibilities for this CRD anomaly included in the engineer's investigation
report.
13
Hypothesis #1.
Hypothesis #2 ..
"The control rod was not fully driven past the latching notch and
the coll et. fingers were just barely hung up on the edge of the
notch. Then after 19 minutes of reactor vibration, the rod drifted
to the next positive notch, Position 12."
"The control rod was not fully driven past the latching notch and
the collet fingers were just barely engaged in a small indentation
created from corrosion of the nitrated surface of the index tube.
This was concluded as somewhat unlikely."
To ensure this event would not recur, the system engineer recommended that when
inserting control rods, the operators should insert the control past the notch until the
control rod position indication system showed "blank" or the "odd" position above the
target position.
After several movements without the anomaly occurring again, the licensee declared
CRD H-12 operable and commenced CRD movements.
- Circulation Water Pump
On July 20, .1998, the licensee identified a leak on the suction piping of the 2A
circulating water pump. Initially the leak was from a 3-inch circumferential crack in the
pipe near the base of the pump. Increased monitoring by the licensee revealed that the
crack grew from* 3 to 7 inches during 3 days.* The licensee repaired the leak.
Shutdown Cooling Pump
On July 16, 1998, during a monthly rotation check, the pump shaft for the 28 shutdown
cooling pump dropped approximately 2 inches while the pump was operating. After the
operators stopped the pump, the pump shaft returned to normal. The licensee
replaced the bearing and was continuing troubleshooting efforts on the shutdown
cooling pump at the end of the inspection period.
213 Emergency Diesel Generator (EOG).
On August 21, 1998, during prechecks for the 2/3 EDG monthly operability surveillance,
the operators discovered one of the twenty cylinder test valves out of position.
Licensee investigations concluded the apparent cause of the mispositioned valve was
vibration. The EDG vendor representative confirmed that there have been instanc.es
where the valve had vibrated open.
Reactor Water Cleanup (RWCU) System
RWCU Auxiliary Pump
At the end of the inspection period, the licensee discovered the suction valve
(3-1201-3) for the Unit 3 RWCU auxiliary pump leaking by, causing pressurization in
14
the pump. The pressurization could cause the pump seal to degrade. The licensee
physically isolated the auxiliary pump from the system. The RWCU auxiliary pump was
normally used to force flow through the RWCU system during periods of low reactor
pressure.
In Inspection Report 98014, Section M2.2, the inspectors documented an instance
where failure of the RWCU auxiliary pump adversely impacted the ability of Unit 3
operators to maintain reactor water level during shutdown and cooldown following the
reactor scram on May 17, 1998. The auxiliary pump has not been available for use
since that event despite the licensee's completion of repair efforts. The unavailability
was caused by operators inability to run and vent the system because the RWCU
system had been maintained at high pressure.
38 RWCU Pump
The licensee discovered excessive leakage on the 38 RWCU pump and discharge
valve. After multiple attempts to repair the pump and discharge valve the leakage
continued through this inspection period. This continued leakage represented rework
for the maintenance organization.
Unit 3 Isolation Condenser Condensate Return Outboard Isolation Valve
On August 10, 1998, after performing quarterly valve timing on the isolation condenser
valves, the main control room Isolation Condenser Temp Hi alarm annunciated. The
receipt of the high temperature alarm was a repeat event. Leakage past the
3-1301-3 valve (Unit 3 isolation condenser condensate return outboard isolation valve)
was suspected as the most likely reason for the high temperature in the isolation .
. condenser. In response to earlier NRC questioning about the system, because of a
prior alarm, the licensee provided documentation that the leak rate testing results and
motor operator testing results were satisfactory. The failure of the 3-1301-3 valve to
seat fully was an intermittent problem that only occurred when the valve was operated
from the control switch on the main control room.903-3 panel. This would suggest that
the high temperature conditions and subsequent main control room alarms were not a
result of poor valve material condition. The inspectors will evaluate licensee resolution
of the matter via routine resident inspections of plant material condition.
Dresden Nuclear Oversight individuals identified an additional concern associated with
the high temperature alarm issue. Operators were inconsistent in the manner in which
they responded to the high temperature alarm. In one instance, operators cycled the
isolation condenser valves following the annunciator procedure in an attempt to clear
the alarm, but did not declare the isolation condenser inoperable while doing so, nor did
they enter the LCO for the isolation condenser. Other times, operators cycled the
isolation condenser valves and declared the isolation condenser inoperable and .
entered the appropriate TS LCO. The licensee documented the valve concerns and
operator concerns via Problem Identification Forms (PIF) 019998-04844, 01998-04841
and 01998-04872. The TS LCO question is enveloped by .the NRC concerns with
respect to operator recognition of TS LCO entry conditions and will be tracked by NRC
15
follow up of licensee actions in response to the violations referenced in this report
(Section 04.2).
c.
Conclusions
Material condition issues continued to adversely affect plant operations. Some of these
issues represented rework for the maintenance organization.
M3
Maintenance Procedures and Documentation
M3.1
Independent Verification
a.
Inspection Scope
The inspectors interviewed licensee personnel and reviewed maintenance procedures
against requirements contained in administrative procedures. The inspectors reviewed
Dresden Instrument Surveillance (DIS) 500-06, "Condenser Low Vacuum Pressure
Switch Channel Calibration and Channel Function Checks" against OAP 07-27
"Independent Verification."
b.
Observations and Findings
The inspectors noted discrepancies between requirements shown in OAP 07-27
"Independent Verification" and various maintenance procedures.
The policy statements in OAP 07-27 stated that when an action or-manipulation (e.g.,
installing a jumper, lifting an electrical lead, operating a switch or breaker) could result
in an immediate threat to safe and reliable plant operation, a "second check" should be
performed instead of an independent verification. In OAP 07-27, the licensee defined
an independent verification as the act of checking a component position independently
of activities related to establishing the component's position (i.e., "Apart in time"). A
second check was defined as positively identifying the correct unit, train, or component,
and reviewing the intended action and expected response before performing the task to
prevent an unintended plant response (i.e., "Apart in Action").
On August 18, 1998, the inspectors questioned the licensee concerning this issue. The
licensee was aware of the discrepancies between OAP 07-27 and actual verification
techniques required in several surveillance tests and used in field work. The licensee
Nuclear Oversight group identified this issue thoroughly in a PIF 1998-04768, on
August 13, 1998. The licensee assigned both the operations and maintenance
organizations to revise the administrative procedures to provide clarity on the types of
verification techniques to be used when performing work activities. The licensee also
assigned the two groups to perform an apparent cause evaluation.
c.
Conclusion
. The inspectors noted discrepancies between requirements shown in OAP 07-27
"Independent Verification" and various maintenance procedures. The licensee's
16
M4
Nuclear Oversight group was aware of these discrepancies and the licensee has taken
steps to address them .
Maintenance Staff Knowledge and Performance
M4.1
Inadvertent Half-scram Caused by Instrument Maintenance Personnel Performance
a.
Inspection Scope (62707)
On July 31, 1998, an unexpected half scram was generated in the Unit 2 control room
during the performance of an instrument surveillance. The inspectors reviewed the
- activities that caused this event.
b.
Observations and Findings
. On July 31, 1998, Instrument Maintenance (IM) Department personnel performed
Dresden Instrument Surveillance (DIS) 500-06, "Condenser Low Vacuum Pressure
Switch Channel Calibration and Channel Function Checks." This surveillance included
steps to jumper the "Low Condenser Vacuum" scram inputs in the reactor protection
system (RPS) logic string. This was done to prevent the receipt of half-scrams during
this surveillance. The licensee adopted this concept as part of its scram reduction
effort.
The licensee planned to remove the condenser vacuum pressure switches (503A, B, C,
and D) from service by attaching a RPS test box to each relay terminal. Each
condenser vacuum switch was to be bypassed,* calibrated and functionally tested
individually. The relays used in this application are HFA-type relays and are on
Panel 902-15 in the main control room. The licensee installed banana jacks on specific
relay terminal posts for ease of landing the leads to the relay.
The Instrument Maintenance Departmen't (IMO) personnel performing the test had
signed off steps indicating pressure switch 2-503A had been removed from service and
. *"
were testing the channel circuitry, when an unexpected half scram signal was received
in the control room. Step 8.a.3 of DIS 500-06 required installation of the RPS test box
leads to terminals 2 and 4 of relay 590-101A. The IMO personnel mistakenly installed
the leads to relay 590-107C (Average Power Range Monitor (APRM) channel #3). The
error occurred even though the DIS included a barrier of independent verification during .
installation of the jumper. A Unit 2 nuclear station operator (NSO) had attempted to
perform the independent verification.
The relays involved in this event were adjacent, but there was reasonable separation
between the two relays. Also, the relays were labeled appropriately.
The licensee performed a prompt investigation into the cause of the vent, and
concluded the cause was "the failure of the IMO Tech and the NSO to perform self-
checking" following a momentary interruption in work. The investigation also stated, "It
was apparent that proper verification techniques were being utilized.during the
. performance of the relay identification."
17
The inspectors independently investigated the event and found that differing causes
existed that were not identified by the licensee. Specifically, the inspectors concluded
that, contrary to the prompt investigations's findings, proper verification techniques
were NOT used. The NSO did not perform an independent verification, but instead
performed the verification concurrently with the instrument mechanic. Dresden
Administrative Procedure (OAP) 07-27, "Independent Verification," defined an
independent verification as the act of checking a component position independently of
activities related to establishing the components's position (i.e., "Apart in time").
Dresden TS 6.8.A required that written procedures be implemented .covering the
applicable procedures recommended in Appendix A of Regulatory Guide (RG) 1.33,
Revision 2, February 1978. Appendix A of RG 1.33 recommended both procedures for
surveillance and calibration tests and for administrative procedures.
Step 6.a.3 of DIS 500-'06 required that leads from the RPS test box be landed on Relay
Post 2 and 4 for relay 590-101A. Step 6.a.6 of DIS 500-06 required that IM personnel
actions be independently verified.
Contrary to the above, on July 31, 1998, the licensee incorrectly installed the jumper on
Relay 590-107C and the independent verifier failed to perform an adequate
independent verification in accordance to OAP 07-27.
As a consequence, APRM #3 protective features were bypassed without the operators
being aware of it, and eventually an unexpected half-scram occurred. Failure to follow
procedures for installation of a jumper on relay 590~101A was considered a violation of
TS 6.8.A (VIO 50-237/98021-02(DRP)).
'
.
This is being treated as a violation consistent with NRC Enforcement Policy
(NUREG 1600) Section Vll.B.1 which states, in part, that licensee identification credit is
not warranted when a licensee identifies a violation as a result of an event where the
root cause of the event is obvious. The inspectors also concluded the licensee's
investigation was superficial and the corrective action defaulted to the easy fix of
coaching the involved individuals.* The licensee's prompt i~vestigation failed to identify
or correct the discrepancies between independent verification requirements described
in the administrative procedure and the actual verification techniques used while
performing the surveillance.
Subsequent to the event, but prior to the inspectors identification of the violation, the
licensee Nuclear Oversight (NO) organization performed an inspection of independent
verification. The NO organization found that independent verifications were not always
being performed correctly. As a *result, the licensee instituted the appropriate corrective
actions (reference Section M3.1). Therefore, no response is required for this violation.
In addition to the causes of the event, the inspectors also assessed the impact of the
error on the plant. The incorrect installation of the RPS test box on 590-107C removed
Unit 2's APRM #3 from service. Nothing on the control panels alerted the operators of
the fact that the required APRM was inadvertently bypassed. The inspectors reviewed
entries in the Unit 2 unit supervisor's logbook and determined that no other APRM
18
C.
channel was inoperable or bypassed at the time of this incident and therefore the
licensee met TS requirements ..
Conclusions
Failure to follow procedures resulted in generation of an unexpected half-scram. That
action also resulted in disabling a reactor core protective feature without operators
being knowledgeable of the situation. A licensee established barrier, independent
verification, failed to prevent this event.
M4.2
Maintenance Refuel Floor Activities Result in Unexpected Main Control Room Alarm
a.
Inspection Scope
The inspectors reviewed the circumstances associated with poor work practices on the
refuel floor that resulted in receipt of a main control room annunciator.
b.
Observations and Findings
On August 5, 1998, licensee and contractor personnel were performing fuel pool
cleanup activities in the Unit 3 fuel pool. Part of the cleanup activities included the use
of a water lance to flush underwater cutting equipment. When workers left the refuel
floor for lunch, they inadvertently left the water supply used for the cleaning activities
turned on. With the water supply left running, level in the fuel pool started to rise and
eventually caused the high water level alarm in the main control room to annunciate.
Operators correctly responded to the alarm in accordance with the annunciator
. response procedures. Refuel floor personnel were informed of the fuel pool high level
alarm, the water input to the pool was secured, and all work stopped on the refuel floor.
Operators successfully lowered fuel pool level back to normal and no adverse safety
consequences occurred as a result of the incident.
The licensee documented the occurrence via Problem Identification Form 01998-0467 4
and initiated a prompt investigation. The licensee implemented corrective actions to
address the issue including management discussion of refuel floor activities at the daily
plan of the day meeting to ensure that all managers would be aware of future refuel'
floor activities.
c.
Conclusions
The operators responded well to this self-revealing, emergent event. The poor work
practices on the refuel floor presented an unnecessary challenge to control room
. operators.
MB
Miscellaneous Maintenance Issues
M8.1
(Closed) Unresolved Item 50-237/249-97003-02: Corrective actions concerning torus
pitting. ComEd stated by Letter JSPLTR #97-0066 dated April 2, 1997, that although
grinding of pits to provide a 4:1 taper was not performed as originally specified, the pits
19
E1
E1.1
E8.1
were considered acceptable. The inspectors reviewed and concurred with the
licensee's engineering evaluation, which supported the conclusion that the pits were
acceptable. The inspectors reviewed Work Packages 004014 and 010177 and
verified that recoating of the pits had been performed to hinder further corrosion. The
inspectors also reviewed work scheduling documentation to confirm that the licensee
scheduled torus inspections, including inspection of underwater portions, for each
refueling outage and that the licensee scheduled corrective actions in response to
March 1998 torus inspection findings. This item is closed.
Ill. Engineering
Conduct of Engineering
Effectiveness of Licensee Corrective Actions for Past Problems
The inspectors reviewed licensee corrective actions associated with older, historical
problems at the station (reference Section ES, "Miscellaneous Engineering Issues").
Some of the older outstanding problems at the station are similar to current problems
experienced by the station that are documented in recent NRC inspection reports.
Examples included HPCI system material condition deficiencies, off-gas system fires,
and reactor vessel post-scram overfill problems due to inadequacies associated with
the feed water level control system. The inspectors closed these issues because the
older items were enveloped by newer, current inspection followup items. While the
licensee ha*s made progress in resolving old concerns, and the current issues are not
as severe as the older items, the repetitiveness of several of the items indicated that
licensee corrective actions had not always been effective at eliminating the concerns.
Miscellaneous Engineering Issues
(Closed} Unresolved Item 50-237/249-94014-04: The failure of the High Pressure
- Coolant Injection System 2-2300-05 valve to perform its intended safety function when
required by an automatic *initiation signal and the concern over the quality of the
ongoing investigation. The licensee subsequently submitted LER 94024,
Docket 50-237, "HPCI Outboard Containment lsoJation Valve Failure to Close due to
Corroded Contacts in Local Push Button Station"; this report discusses the LER ..
Report 94014 also described an instance of a failure to perform a 50.59 evaluation on
the support stand for the local controller of the HPCI outboard containment isolation
valve. The licensee could not find any 1994 tracking items for failing to perform an
evaluation of the support stand. Licensee engineers walked down the support and
determined that it was currently adequate, but the engineers were unable to locate any
supporting calculations. Ori July 28, 1998, the licensee initiated PIF# 01998-04561 to
enter the apparent lack of a 50.59 evaluation into the corrective actions process, and*
subsequently assigned NTS Item 23720198357501 with a due date of October 2, 1998,
to address the 50.59 screening. This unresolved item is closed.
. 20
EB.2
{Closed) Inspection Followup Items (I Fis) 50-237 /249-94016-01. 50-237 /249-94016-04.
50-237/249-94016-05. 50-237/249-94016-06. 50-237/249-94016-07; Weak Design
Calculation Control: The above items were all items from the System Based Instrument
and Control Inspection (SBICI).
The following statement was included in the SBICI team report for each of the above
I Fis.
"Based on other margins identified in the calculation, the team concluded the above
items would not affect operability, however, these items represent another example of
weak design calculation control."
The inspectors reviewed the corrective actions taken for the weak design calculation
control. The licensee stated that from 1994 to 1996, Dresden was part of a program to
obtain all the design basis and calculations from the Architectural Engineering and
Design Groups for the plants. The licensee has now stored the calculation data basis
in the Electronic Work Control System (EWCS) Controlled Documents for Calcuiations.
The documents were available as necessary to plant personnel on a read only bases.
Selected clerks accomplished changes to the information.
The licensee has entered all the calculations for the plant into the EWCS, which may
be read or printed by anyone with access to the data base. This issue is closed.
EB.3
{Closed) Unresolved Item 50-237/249-96002-11: Resolution of NRG-identified Updated
Final Safety Analysis Report (UFSAR) issues. This unresolved item involved NRC-
identified discrepancies in information in the UFSAR regarding the following items:
containment locked valve status, diesel fuel oil storage tank overflow, ACAD system
status, toxic gas analyzer, and differences between condensate storage tanks A and B
relative to the HPCI system's dedicated suction. Report 96004 added an additional
discrepancy between the UFSAR and the diesel generator fuel oil day tank to this item.
The item was open pending review of the licensee's corrective actions.
These discrepancies reflected a historical lack of emphasis on maintaining the UFSAR.
The licensee acknowledged this weakness and implemented actions to assure proper
maintenance of the UFSAR. This item is now closed. Note that the following actions
addressed the specific issues of URI 96002-11:
21
Issue
Resolution and Significance
Incorrect Containment Locked Valve
50-person team rewrote and re-verified
Status
locked valve checklists. Violation 50-237;
50-249/96004-02 issued for corrective
actions associated with locked valve status.
Diesel Fuel Oil Storage Tank
UFSAR modified. This UFSAR error was
Overflow
considered minor.
ACAD System Status
UFSAR modified. This UFSAR error was
considered minor.
Toxic Gas Analyzer
Emergency Operating Procedures revised.
LER 237 96-003, "Main Control Room HVAC
Outside of Design Basis due to Inadequate
Implementation of Modification" issued.
This UFSAR error was tracked under the
LER.*
CST A and CST B HPCI Dedicated
UFSAR modified. This UFSAR error was
Suction differences
considered minor because annunciators and
alarms provided administrative control of
suction.
E8.4
{Closed) Unresolved Item 50-237/249-96004-06: Status of Safety Systems During
Valve Stroke Tests. This unresolved item was to.evaluate the acceptability of not
declaring emergency core cooling systems (ECCS) inoperable during motor operated
valve stroke tests. The concern was that the valves took longer to return to their safety
position than the safety analysis assumed for the ECCS to operate post-accident. The
licensee evaluated the concern and determined that declaring the systems inoperable
during stroke time testing was more feasible than redoing the safety analysis to .
account for the longer stroke times. The licensee accordingly altered the surveillance
procedures to reflect this position. This item is closed.
.E8.5
E8.6
(Closed) Unresolved Item 50-237/249-96004-07: Weak Justification for Environmental
Qualification of Pressure Controller. The licensee reperformed the calculation to
support operability of the controller in the post-accident environment. This item is
closed.
{Closed) Inspection Followup Item 50-249/96006-02: Thirty-day Special Report:
Inoperable Recombiners Due to Short Duration Off Gas System Fires. The licensee
implemented a number of corrective actions in response to short duration off gas
system fires in 1995. These actions were not completely effective, as evidenced by the
occurrence of fires in the 3A off Gas train on December 6, 1997, and January 13, 1998,
(reference IR 50-237/249-97028(DRP)). The licensee assigned multiple nuclear
tracking system items to track and implement improvements to the off gas system. The
22
NRG will review these actions as part of routine resident core inspections. This item is
closed.
EB.7
(Closed) Unresolved Item 50-237/249-96006-10: The reactor building ventilation
system did not meet the flow values listed on Updated Final Safety Analysis Report
.(UFSAR), Figure 9.4-15. This issue was open pending the inspectors' review of the
licensee's evaluation. The written response provided to the inspectors stated that the
licensee did not intend to make the "Information Only" drawings part of the design basis
of the plant. Section 1. 7, "Drawings and other Detailed Information," of the UFSAR *
also stated "Selected P&IDs shown in the UFSAR are for information only."
The licensee researched the issue in 1996 and found no references to specific flow
values in the text. The licensee also reviewed the original GE design and found that
references to air flow were only coupled to maintaining reactor building temperatures.
The licensee determined that, as described in text of the UFSAR, the design basis for
the ventilation system was to maintain reactor building temperatures, to provided at
least one free-volume change per hour, and to maintain at least-1/4" differential
pressure (dp) within the reactor building, and at least -1/4" dp between clean and
potentially contaminated areas.
During the current inspection period, the inspectors requested that the licensee show
how the reactor building ventilation system met the design basis determined in 1996.
The system engineer informed the inspectors that no tests or calculations existed to
show that the system met its design basis. The inspector asked if there were any plans*
to change the UFSAR, and the system engineer responded that there were none.
The inspectors were concerned that the licensee had not shown that the plant was
within compliance with the UFSAR despite the two years since the inspectors raised the
original concern. The inspectors discussed the issue with the plant management, and
the licensee subsequently performed tests and concluded that the reactor building
ventilation could exchange two volumes per hour.
The original unresolved item was a concern that the UFSAR design basis of the reactor
building ventilation system was shown on UFSAR Figure 9.4-15. The ability of the
system to meet the flow rates shown on the drawing was the crux of the concern.
Figure 9.4-15 was a photocopy of Critical Drawing M-269 Rev Q, "Diagram of Reactor
Building Ventilation," and was labeled "For Information Only." The inspectors noted
that Figure 9.4-15 was also marked, "This drawing is superseded by M-269, Sh. 1 & 2,"
Drawings M-269, Sheets 1 and 2 were not part of the UFSAR.
Paragraph 71(e) of 10 CFR Part 50 states that the UFSAR shall be revised to include
changes made in the facility. The inspectors were concerned that the use of
superseded "information only" drawings in the UFSAR may not comply with
. 10 CFR 50.71(e). The original Unresolved Item 50-237/249-96006-10 is closed.
However, the overall use of "information only" drawings as described in UFSAR
Section 1.7, is considered unresolved pending the inspector's review of the issue with
the office of Nuclear Reactor Regulation (URI 50_-237/249-98021-03(DRP)) .
23
.J
E8.8
(Closed) Unresolved Item 50-237/249-97013-06(DRP)}: 250 VDC Battery Loading.
This item was open pending further NRC review of the UFSAR, the licensee's response
to the NRC Independent Safety Inspection Report, and the revised battery calculation.
The licensee identified on August 12, 1997, that the last TS battery load profile
surveillance test did not use the worst-case load profile. Revision 11, of the battery
- loading calculation (PMED 898230-01) had the same error. The worst-case profile only
existed when the licensee aligned a unit to the swing charger, and the same unit
powered the swing charger, and the 2/3 emergency diesel generator tripped.
Previously, the licensee had based the worst-case profile on having the Unit 2(3)
charger in service ~nd the Unit 2(3) diesel tripping. At Dresden, the 2/3 swing charger
is a spare charger, and not normally in use. This item was open pending further NRC
review of the UFSAR, the licensee's response to the NRC Independent Safety
Inspection Report, and the revised battery calculation.
As corrective action to the error, the licensee revised the battery and charger alignment
procedures to prevent the worst case scenario by prohibiting aligning the 2/3 swing
charger to the same unit from which the charger was energized. This prohibition made
the previously analyzed trip of the Unit 2(3) diesel bounding.
The initial discovery of the new worst-case scenario was determined by the licensee not
to be reportable to the NRC. During review of this unresolved item, the inspectors
requested that the licensee confirm this decision. The licensee concluded that the
event was reportable and commenced making a LER. The inspectors will review this
issue, along with the timeliness of the reporting of the event to the NRC, after receipt of
the LER.
This unresolved item is closed.
E8.9
(Closed) URI 50-237/249-98007-04: Concern that a lake hot canal dike failure might .
lower the plant intake canal water level to below the 495' Mean Sea Level (MSL)
analyzed in the UFSAR. ComEd responded to this URI by docketed letter dated
June 25, 1998, and stated that the lowest elevations of all connections of the lake hot
and cold canals to the Units 2 and 3 intake and discharge canals were at 496' MSL.
Therefore, failure of the lake canal dikes could not lower the intake and discharge canal
water levels to less than 495' MSL. The inspectorreviewed Sheets 1 and 2 of the
Circulating Water Flumes - Plan and Profile Drawings (S-17 and S-18), which indicated
that the lowest elevations of the lake hot and cold canal connections to the intake and
discharge canals were at 496' MSL. The inspector determined that any lake canal dike
failure was properly bounded by the Dresden Dam failure UFSAR analysis. This item is
closed .
24
E8.1 O (Closed) LER 50-237/94024-00: HPCI Outboard Containment Isolation Valve Failure to
Close due to Corroded Contacts in Local Push Button Station .
On August 4, 1994, Unit 2 was at 99 percent of full power. The Unit 2 HPCI system
failed its monthly operating surveillance because one of the HPCI turbine exhaust
check valves failed closed. The HPCI system failure required the licensee to shut down
Unit2.
On August 9, 1994, during the shutdown for repairing the HPCI system, the Unit 2
HPCI system outboard containment isolation valve, 2-2301-5, should have closed when
reactor pressure dropped below 80 psig, but the valve failed to close automatically.
However, the inboard valve closed, so the HPCI system valves accomplished
containment isolation. The operators could not close the outboard valve by use of the
control room switches either, but the operators did eventually close the valve by use of
the local handwheel.
The licensee found that the valve's local control station push button contacts were
corroded. The corrosion made an open circuit that prevented operation of the valve.
The licensee cleaned the contacts on the HPCI system valve controller, and did the
same for about 130 other safety-related local controllers. Also, the licensee *
implemented an every-other-refueling maintenance task to clean the contacts.
The inspectors conducted a search for problems related to corroded contacts on local
valve controls, and the search showed no additional problems. The inspectors verified
that work documents showed that valves 2-2301-5 and 3-2301-5 had received
subsequent cleanings, and were currently cleaned. This LER is closed.
IV. Plant Support Areas
Radiological Protection and Chemistry (RP & C}
R4
Staff Knowledge and Performance in RP&C (RP & C}
R4.1
Release of Contaminated Material Off-Site
a.
Inspection Scope
On August 13, 1998, the licensee released a truckload of dirt offsite. The licensee
subsequently sampled the dirt and two of the four samples exceeded the licensee's
radiological criteria for free-release of material from the station.
b.
Observation and Findings
On August 13, 1998, the licensee performed excavating to support repairs on an
underground storm sewer. The licensee was performing the work in a non
radiologically controlled area of the site. A contract radiation protection technician
25
associated with Unit 1 was overseeing the work and did not perform the sampling
required for a full unconditional. release of the material.
Consequently, the licensee released a truck filled with dirt from the excavation from the
site. On August 14, 1998, the licensee filled a second truck with dirt from the job.
Utility radiation protection personnel observed the job and questioned why licensee
personnel did not take isotopic analysis samples before releasing the material. At that
point, the licensee identified that a truck was released the prior day without the
performance of the required isotopic analysis. The utility then performed an isotopic
analysis of the dirt that had already been released from the site. Two of the four
samples indicated levels of Cesium-137 that were just above the licensee's free release
- criteria. The licensee collected the material and returned it to the site.
The licensee documented the occurrence via PIF 01998-04836. The licensee informed
the inspectors that a full root cause analysis would be performed to determine how
barriers broke down to allow the material to be released: The radiological
consequences of the event were minor. The inspectors will review the root cause
analysis during routine resident and regional plant support inspection activities.
c.
Conclusions
X1
While the radiological consequences of the event were minor, breakdowns in licensee
processes and practices resulted in the release of contaminated soil from the site. *
V. Ma~agement Meetings
Exit Meeting Summary
The inspectors presented the inspection results to members of license management at
the conclusion of the inspection on August 25, 1998. The licensee acknowledged the
findings presented. The inspectors asked the licensee whether any materials
examined during the inspection should be considered proprietary. No proprietary
information was identified .
26
"
Partial List of Persons Contacted
Licensee
L. Aldrich, Radiation Protection Manager
J. Almon, Training Manager
P. Boyle, Chemistry Department Head
S. Butterfield, Regulatory Assurance NRG Coordinator
P. Chabot, Engineering Manager
L. Coyle, Operations SOS
R. Fisher, Maintenance Manager
T. Fuhs, Regulatory Service, NLA
J. Harlach, Supervisor Service Manager
M. Heffley, Site Vice President
R. Kelly, Regulatory Assurance
W. Lipscomb, Site Vice President Staff
M. Milly, Supply Maintenance Department Head
M. Pacilio, Work Control and Outage Manager
F. Spangenberg, Regulatory Assurance Manager
S. Stiles, Nuclear Oversight Manager
P. Swafford, Station Manager
R. Weidner, Corrective Action Program Supervisor
K. Riemer, Senior Resident Inspector
D. Roth, Resident Inspector
B. Dickson, Resident Inspector
M. Ring, Chief Reactor Projects Branch 1
27
. "
I
List of Inspection Procedures Used
IP 62707:
IP 71707:
Maintenance Observations
Plant Operations
IP.71750:
IP 92903:
IP 92902:
Plant Support Activities
Followup - Engineering
Followup - Maintenance
List of Items Opened, Closed,. and Discussed
50-249-98021-01
50-237-98021-02
50-2371249-98021-03
Closed
237/249-94014-04
237/249-94016-01;
04; 05; 06; and 07
2371249-95009-02
2371249-95015-07
249-96006-02
237/249-96002-11
2371249-96004-06
2371249-96004-07
237/249-96006-10
2371249-97003-02
237197013-06
2371249-98007-04
237-90002-02
237-9500,1-01
237-95006-00
237-95013-00
237-95015-00&01
Violation of TS 3.8.D "Control Room Emergency
Ventilation.
Failure to Follow Procedures
Use of "Information Only" drawings as described in
UFSAR Section 1.7.
IFI
IFI
IFI
LER
LER
'
LER
LER
LER
Failure of HPCI System Valve to Perform its Intended
Safety Function
Weak Design Calculation Control
OOS and Equipment Configuration Control Problems
Drawing Error
Thirty-day Special Report: Inoperable Recombiners
Resolution of NRC-ldentified UFSAR Issues
Status of Safety Systems During Valve Stroke Tests.
Weak Justification for Environmental Qualification of
Pressure Controller
Reactor Building Ventilation System did not Meet Flow
Values on FSAR
Corrective Actions Concerning Torus Pitting
250 VDC Battery Loading
Concern That a Lake Hot Canal Dike Failure Might Lower
Plant Intake Canal. Water Level
Reactor Scram Following Condensate/Condensate
Booster Pump Failure due to Internal Failure
Scram From Main Turbine Stop Valve Closure Due to
Moisture Separator Level High High
TIP System Isolation Does Not Have "Seal in"Logic on
Group II Isolation
.
Inadequate Sampling of Service Water Effluent Due to
Use of a Superseded Procedure and Recent System
Configuration Change
Leakage Limit Exceeded Due to Excessive Leakage Past
28
j
237-95017-00
LER
Containment Cooling Service Water Vault Penetration
Seals Failed Leak Test Due to Being Out of Adjustment
249-95008-01
LER
Scram From Main Turbine Stop Naive Closure Due to
Turbine Trip on High Vibration
249-95010-00
LER
Inadequate LCO Entry Due to Inadequate Control of
Decay Heat During Cooldown
237-94024-00
LER
HPCI Outboard Containment Isolation Valve Failure to
Close
237-97013~00
LER
HighPressure Coolant Injection System Inoperable Due to
Excessive Cycling of the Gland Seal Condenser Drain
Pump Due to Level Switch Malfunction.
249-97-014-00
LER
High Pressure Coolant Injection System Inoperable Due to
Gland Seal Leakoff Condenser Drain Pump Low Level
Shut Off Switch Failure Caused by a Misaligned Switch
Lever Arm.
249-98001-00
LER
High Pressure Coolant Injection System Inoperable Due to
Gland Seal Leakoff Condenser level Control Malfunction
Caused by a Loose LLJg on the Drain Pump Automatic
Start Relay.
249-98-002-00
LER
High Pressure Coolant Injection System Inoperable Due to
Gland Seal Leakoff Condenser level Control Malfunction
from a Drain Pump Start Level Switch Failure Cause by
Original by Original Design Deficiency.
237-9.8-009-00
LER
High Pressure Coolant Injection System Inoperable Due to
Gland Seal Leakoff Condenser Level Control Malfunction
from a Drain Pump Start Level Switch Failure Caused by
Manufacturer Design Deficiency.
Discussed
None
29
ccsw
CFR
OAP
DATR
DIS
DOA
dp
DTS
EOG
EPN
EWCS
IFI
IMO
IR
LCO
LER
NCAD
NSO
NTS
oos
TS
LIST OF ACRONYMS USED
Atmospheric Containment Atmosphere Dilution
Apparent Cause Evaluation
Average Power Range Monitor
Containment Cooling Service Water
Code of Federal Regulations
Condensate Storage Tank
Dresden Administrative Procedure
Dresden Administrative Technical Requirements
Dresden Instrument Surveillance
Dresden Operating Abnormal
Dresden Operations Surveillance
Differential Pressure
Dresden Technical Surveillance
- Electronic Part Number
Electronic Work Control System
High Pressure Coolant Injection
Heating Ventilation and Air Conditioning
Inspector Followup Item
Instrument Maintenance Department
Inspection Report
Limiting Condition for Operation
Licensee Event Report
Low Pressure Coolant Injection
Master Equipment List
Mean Sea Level
Nitrogen Containment Atmosphere Dilution
Nuclear Station Operator
Nuclear Tracking System
Out-of-Service
Post-Accident Monitoring
Piping and Instrument Drawing
Problem Identification Form
Plant On-site Review Committee
Refrigeration Cooling Unit
Regulatory Guide
Traversing In-Core Probe
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
30