ML17191A846
| ML17191A846 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 08/07/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17191A844 | List: |
| References | |
| 50-237-98-19, 50-249-98-19, NUDOCS 9808270315 | |
| Download: ML17191A846 (30) | |
See also: IR 05000237/1998019
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION Ill
Docket Nos:
License Nos:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9808270315 980807
ADOCK 05000237
G
50-237; 50-249
50-237/98019(DRP); 50-249/98019(DRP)
Commonwealth Edison Company
Dresden Nuclear Station, Units 2 and 3
6500 North Dresden Road
Morris, IL 60450
May 28 through July 14, 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
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 50-237/9819(DRP); 50-249/98019(DRP)
This inspection included routine resident inspection from May 28 through July 14, 1998,
augmented by regional inspectors.
Operations
The material condition (failed shut vent valve) of the 2A electro hydraulic control (EHC)
pump caused the pump not to vent. Operators continued to run the pump despite
multiple indications of equipment trouble. After about 3 minutes, the pump forced a slug
of air through the EHC system, where the slug caused pressure oscillations and an
automatic turbine trip and reactor scram. Subsequent event follow-up by the event
response team and the plant operations review committee was considered thorough and
demanding. (Section 01.2)
The operators responded to the turbine trip and scram correctly and in accordance with
procedures. (Section 01.2)
The operators in the control room performed correctly during the startup from the scram.
Communications were clear and complete, and good command and control was evident.
The inspectors identified no significant issues. (Section 01.3)
Routine performance was generally acceptable. However, three times during this period
operators failed to recognize issues addressed in Technical Specifications until prompted
- by other operators. (Sections 04.1, 04.2)
Overall, 'the Quality and Safety Assessment oversight of operations was good.
Audits of recent operational activities were informative, relevant, and demonstrated good
attention to detail by the auditors. (Section 07 .1)
Areas of the response to the NRC's request for information under 1 O CFR 50.54(f)
regarding safety performance at Commonwealth Edison reviewed by the inspectors
- showed good performance. (Section 08.3)
Maintenance
No concerns were identified with maintenance activities directly observed. The
mechanics and technicians followed procedures and work instructions, and correctly *
documented the results. Issues discussed at station management meetings showed that
the licensee was placing importance on emergent equipment problems commensurate
with operations' requests, and that the licensee was actively using its planning
procedures to assign work priorities. Review of issues identified in problem identification
forms (PIFs) did not typically reveal significant rework or maintenance errors.
(Section M1 .1)
The material condition of the plant equipment affected station operation and availability .
For example, a failure in the electro hydraulic control pump's vent valve led to a reactor
2
scram, an emergency diesel g~nerator failed a surveillance test due to a loose wire in the
governor system, and the security diesel generator started due to failed electrical
distribution systems, then twice tripped off due to material condition. (Section M2.1)
A potential common mode failure impacted the operability of the safety-related
Containment Cooling Service Water (CCSW) pumps. The failure occurred during the
conduct of routine maintenance activities. Once the problem was identified, the station
responded aggressively to verify operability of the remaining CCSW pumps.
(Section M2.2)
Maintenance on the core spray system was performed on-line for the first time instead of
during a refueling outage. Problems venting the core spray system following the
maintenance led to additional unplanned core spray system outage time. (Section M4.1)
Engineering
The licensee organized a team to determine methods of scram and derate reduction and
improve material condition. This effort had the potential to improve plant material
condition and reduce significant challenges to the operators. (Section E2.1)
The post accident monitoring (PAM) instrumentation was lost when a nonsafety-related
circuit tripped, revealing that instruments required by Technical Specifications were
inappropriately powered by nonsafety-related circuits. The selected instruments did not
meet the requirements specified in the Updated Final Safety Analysis Report (UFSAR).
Engineering personnel reviewing the loss of PAM took 3 days to conclude that the
instruments were inoperable due to use of nonsafety-related power. (Section E4.1)
The root cause report on the loss of PAM instrumentation performed by the licensee
contained factual errors and information that could not be proven. The root cause report
failed to discuss significant issues. (Section E4.1)
Plant Support
Overall, the licensee's radiation protection staff enforced the plant's radiological control
standards. The licensee continued to use personnel functioning as "greeters" to assure
that workers entering the radiologically controlled area were aware of dose rates and
administrative protection requirements. (Section R 1.1)
The security diesel failed twice when called upon and once during a test run due to
material condition. (Section S2.1)
3
Report Details
Summary of Plant Status
Unit 2 started the period at full power. On June 20, 1998, the Unit 2 main turbine tripped and*
Unit 2 automatically scrammed from full power, thus entering a forced outage (D2F33). Unit 2
was r~started on June 22, and synchronized to the grid later that day. Unit 2 was restored to full
power on June 23, 1998, and remained at full power throughout the rest of the inspection period,
except for planned load drops to support maintenance and testing activities.
Starting this inspection period, Unit 3 was still increasing power from the planned transformer
replacement outage (D3P02). After reaching full power, Unit 3 remained there throughout the
inspection period, except for planned load drops to support maintenance and testing.
Power on both units was slightly limited to keep feedwater flow below 9. 735 Mlbm/h, the
feedwater flow limit required to maintain the units within their fuel cycle analyses.
I. Operations
01
Conduct of Operations
01.1
General Comments (71707)
Using. Inspection Procedu.re 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:
05/28/98
05/29/98
06/10/98
06/20/98
(Units 2, 3) Safeguards system degradation related to power supply
functions.
(Units 2, 3) Safeguards system degradation related to power supply
functions.
(Units 2, 3) Safeguards system degradation related to power supply
functions.
(Unit 2) Automatic reactor scram signal due to main turbine trip
caused by electro-hydraulic control (EHC) system pressure
perturbations during EHC pump start.
01.2
Reactor Scram Due to Main Turbine Trip (Unit 2)
a.
Inspection Scope (71707)
- On June 20, 1998, the Unit 2 reactor automatically scrammed from approximately
99. percent of full power due to a trip of the main turbine. Inspectors reviewed
4
operator and equipment performance following the scram and reviewed the
results of the licensee's scram investigation team.
b.
Observations and Findings
On June 20, 1998, the licensee completed preventive maintenance and inspection of the
chain drive and coupling for the 2A electro hydraulic control (EHC) pump. The
maintenance was non-intrusive and involved tightening the priming pump's drive chain
and greasing and alignment of the coupling.
After completion of the work, with the 28 EHC pump running normally, the operators
started the 2A EHC pump. The EHC pumps normally operate around 1550 psig. The
non-licensed operator monitoring the start of the 2A EHC pump reported to the control
room that the pump start was abnormal because the 2A EHC pump was too quiet and
discharge pressure was only 340 psig. The licensed operator in the control room saw
that the EHC pump oil "at pressure" light in the control room also did not illuminate ..
Despite the observed abnormalities, the operators chose to continue running the .
2A EHC pump to allow collection of vibration data. About 3 minutes after the pump start,
the EHC pump made a loud noise (an indication of cavitation), the turbine tripped, and the
reactor scrammed.
Operators properly entered and executed the appropriate reactor scram procedures.
Operators responded well to the unexpected reactor trip and placed the plant in a stable* *
condition.
The automatic turbine trip was caused by a low EHC system pressure signal. The low
EHC system pressure signal was apparently caused by pressure oscillations associated
with a slug of air moving through the EHC system.
The licensee formed an event re~ponse team. Licensee personnel could not determine
how the air entered the 2A EHC pump .. The design of the pump system included a
passive vent valve. During the post-scram investigation, the licensee found that the
passive vent valve was failed shut. The failure caused air from the pump to move
through the EHC system, instead of venting out, thus creating the pressure oscillations.
The licensee also found that the 2A EHC pump's pressure indicator was indicating
350 psig to 400 psig too high, so when the non-licensed operator reported seeing abo.ut
340 discharge pressure, the pressure was probably zero. Also, the at-rest pressure
indication was about 350 psig instead of zero. Since the non-licensed operator did not
report any abnormal pressures during pre-start checks, it appeared that the non-licensed
operator's checks were not thorough. In Inspection Report 98003, the NRC documented
a similar example of operators failing to verify discharge pressure on a diesel lube oil
pump following startup.
The inspectors concluded that the event response team performed a thorough
investigation. The plant operations review committee review of the team's results was
thorough and demanding.
Additional followup of this event will be performed after receipt of the licensee event
report .
5
c.
Conclusions
A material condition deficiency on the 2A EHC system caused the pump to not vent
correctly. Operators continued to run the pump despite multiple indications of equipment
trouble. After about 3 minutes, the pump forced the unvented slug of air through the EHC
system, where the slug caused pressure oscillations and an automatic turbine trip and
reactor scram.
The operators responded to the turbine trip and scram correctly and in accordance with
procedures.
The licensee's inves.tigation and review of the event were good.
01.3
Startup Operations (Unit 2)
. The inspectors assessed the licensee's preparation for and performance during the
startup of Unit 2 on June 22, 1998. The review included direct control room observation
and field walkdowns.
Operators in the control room performed correctly. Communicalions were clear and
complete and good command and control was evident. No significant issues were
identified by the inspectors during the startup.
The inspectors identified several small leaks and some poor housekeeping in the reactor
and turbine buildings. The inspectors concluded that.the issues should .have been
identified by plan~ staff before NRC-identification.
Overall, the startup was performed correctly.
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 operator standards and procedures.
b.
Observations and Findings
Routine Operations
Overall, 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
several instances where the operators' performance was not adequate.
On June 1, 1998, power to some Unit 3 control room indications for Post-Accident
Monitoring (PAM) was lost when a space heater plugged into an outlet in the control room
was turned on and overloaded a regular lighting circuit. The operators entered the
6
correct Technical Specification (TS) and limiting condition for operation (LCO) at the time,
but incorrectly declared the instrumentation operable when the power to the indications
was restored. The operators also incorrectly screened the problem identification form
and failed to request that engineering personnel perform an operability evaluation.
Subsequent reviews of the logs and information available to operations failed to identify
that the PAM instruments were still inoperable due to being powered from a nonsafety-
relat.ed power source. In this instance, peer checks by operations failed. Four days later,
the operators retroactively declared the instrumentation inoperable. Additional
discussions of this issue are contained in Sections 04.2 and E4.1.
On June 5, 1998, the inspectors watched the operators perform DOS 2300-03, "High
Pressure Coolant System Operability Surveillance." The operators completed the High
Pressure Coolant Injection (HPCI) system pump flowrate verification section of the
surveillance test, and were deenergizing breakers for the HPCI system warm fast start.
At this point, a notation in the procedure stated, "The operating High Voltage Operator will
remain stationed at the 250 VDC bus until completion of the portion of the test requiring
valves be electrically isolated." During performance, one licensed operator directed the
high voltage operator to leave the 250 VDC bus and proceed to the HPCI room. A
second licensed operator overheard and reminded the first operate~ of the notation.
Before the second operator's intervention, the primary operator had not been soliciting
peer reviews; use of peer reviews was a recommended station standard.
An additional notation in the procedure stated that the time between the manual initiation
phase of the test and the fast initiation should be minimized to reduce the possibility of
damage to the HPCI turbine caused by thermally induced stress. The unit supervisor had
- to call an additional field operator to go to the HPCI system pump room and observe
HPCI during the fast start, so the time was not reduced.
Unrecognized Core Spray TS LCO Entry
Operators missed a required entry into a TS LCO for primary containment isolation
system (PCIS) valves upon system restoration from the core spray system outage. In a
second instance, the operators failed to maintain the req~ired torus-to-drywell differential
pressure. The inspectors reviewed the circumstances associated with these matters.
Following completion of work on the core spray* system, the operations department
. authorized clearance of out-of-service (OOS) 98006973 associated with the work on
July 7, 1998. The clearance involved the 3-1402-3A valve (Core Spray Pump Suction*
Valve From Torus) and the 3-1402-38A valve (Core Spray Pump Minimum Flow Valve),
both of which were PCIS valves.
The valves were required to be cycled, not just opened, to verify their operability.
TS 3.7.D stated:
With one or more of the primary containment isolation valves inoperable,
maintain at least one isolation valve OPERABLE in each affected
penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:
7
a.
Restore the inoperable valve to OPERABLE status, or
b.
Isolate each affected penetration by use of at least one deactivated
automatic valve secured in the isolated position, or
c.
Isolate each affected penetration by use of at least one closed
manual valve or blind flange.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and
in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Additionally, OOS 98006973 stated in the "Ops Hang Info" section "must enter TS 3.7.D
for PCIS vlvs on which work will be done, on RTS must maintain one vlv closed to meet
TS." The evening shift operating crew missed both the statement in the OOS and the TS
LCO entry requirement. The subsequent operating crew caught the omission, entered
the appropriate LCO, and* performed the required actions before expiration of the LCO
time clock.
Unrecognized Torus-to-Drywell Differential Pressure TS LCO Entry
On June 23, 1998, the licensee identified that Unit 2 operators unknowingly allowed the
torus to drywell differential pressure (dP) to decrease below the TS required dP value.
Technical Specification 3.7.H stated, "Differential pressure between the drywell and the
suppression chamber shall be :2: 1.0 psid." At the time of the event, the licensee was
performing Dresden Instrument Surveillance (DIS) 1600-15, "Drywell to Torus dP
Controller Calibration."
Shortly after the start of this surveillance test, one operator noted that the drywell-to-torus
dP was less than 1.0 psid and discussed it with another operator, but the operators both
incorrectly concluded that the pressure indication was false due to the ongoing
calibration. At the time of the surveillance many other evolutions were ongoing, one of
these evolutions ~equired a valve (2-1601-58) in the drywell-to-torus differential pressure
control (pumpback)system to be open. This open valve led to some loss of the drywell-
to-torus required dP. The loss of drywell-to-torus dP condition existed for approximately
45 minutes before the licensee fully recognized that the TS limit had been exceeded and
the plant was in an LCO.
An investigation by the licensee revealed some operating staff deficiencies, including the *
failure of the unit supervisor to hold .a pre-job briefing before the performance of the
surveillance test. This action resulted in a lack of task assignment for monitoring
containment parameters.. Additionally, the investigation concluded that the primary NSO
failed to perform the primary job responsibility of monitoring the control panels. The
investigation also recognized an additional configuration management issue that
.contributed to this event.
The operators restored the drywell-to-torus dP to the required specification in
approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 40 minutes after the initial loss of one psid: This time was
within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> limitation provided in the action statement of the TS. However, this
event represented another example of operations personnel failing to recognize that
TS entry conditions had been exceeded .
8
Nuclear Oversight Findings on Unrecognized TS LCO Entry
A review conducted by Quality and Safety Assessment identified another similar failure in
which operators failed to recognize or log entry into an LCO for secondary containment.
At the end of the inspection period, the review was not complete.
Regulatory Significance
The licensee did not exceed the times specified in the LCO for the primary containment *
- isolation system and for the torus-to-drywell differential pressure. Therefore, the
applicable TSs were not violated. However, the failures to recognize and log entries into
two LCOs violated the administrative requirements of the TSs.
Dresden 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 above, operations personnel failed to identify the entry into the LCO
condition for primary isolation containment valves, and failed to identify the entry into the
LCO for torus-to-drywell differential pressure. These were two examples of a violation of
TS 6.8.A. However, these examples of a violation were licensee identified and corrected.
The licensee identified and corrected violation is being treated as a Non-Cited Violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy, NUREG-1600,
Revision 1. The inspectors noted that during this inspection period, there were three
issues related to recognition of entry into TSs (core spray isolation valves, torus-to,.
drywell pressure, secondary containment). A fourth related issue, discussed in
Section 04.2 of this report, was.recognition of failed post-accident monitoring
instrumentation.
c.
Conclusions
Routine performance was generally acceptable. Three times during this period operators
failed to recognize issues addressed in TSs until prompted by other operators. The initial
peer checks by operations were not always timely or successful. The negative trend in
operators' recognition of LCOs was of concern.
04.2
Post-Accident Monitoring Technical Specification
a.
Inspection Scope (71707)
The inspectors reviewed the response of operations department personnel to a loss of
control room indication. Additional discussions are contained in Section E4.1 of this
report.
9
b.
Observations and Findings
On June 1, 1998, an operator turned on a space heater normally kept under the
operator's desk. Some control room indications, the heater, and some temporarily
installed scram monitoring instruments were lost when the circuit that energized the
heater overloaded and t("ipped. The indications lost included the post-accident monitoring
(PAM) indications required by TS 3.2.F, "Accident Monitoring," for Drywell Pressure -
Narrow Range, and Torus Pressure. On June 1, the Unit 3 supervisor's log recorded the
entry into a 30-day LCO due to the loss of one channel.
Operators entered the appropriate LCOs for the PAM indications upon the loss of the
indications. The licensee found the breaker that had tripped and reset it, thus restoring
the indications. Operators then exited the LCO, recorded the events in the logs, and
. wrote a Problem Identification Form (PIF).
As discussed in Section E4.1 of this report, the overload showed that the PAM
instrumentation was not on safety-related power and was not operable. Therefore, the
operating crew should not have exited the LCO ..
The heater was plugged into an ordinary power strip, along with a computer and a radio
charger. The power strip was plugged into an outlet, and the outlet was labeled as
requiring unit supervisor permission to use. However, the label was at the outlet, far
under a desk, and only readable by crawling under the desk. The inspectors surveyed a
few operators and found that not all were aware of the warning on the outlet. Therefore,
the written communication (warning label) failed. The licensee was unable to identify
when the initial warning placards by the outlets were placed.
The Unit Supervisor's log recorded the event. However, two shifts later the inspectors
determined that the shift manager was unaware of the event The shift manager
determined that the computerized log system had failed to .transfer two entries in the
electronic unit supervisor's log to the shift manager's log. One other instance of
information failing to transfer was identified by the shift manager. Therefore, electronic
communications (electronic logs) failed.
The inspectors were the first to inform the shift manager about the event, although two
shifts had passed. The inspectors also were the first to inform the operations manager.
Throughout the following days, the inspectors observed that the .licensee's reaction to the
event was slow and minimal.
The unit supervisor also recorded the event in a PIF, and the PIF was signed by the
afternoon-shift shift manager. However, by the next day shift, the inspectors found that
the day-shift shift manager was unaware of the event. Therefore, oral communication
(face-to-face turnovers) failed.
Part of the short-term corrective actions, while engineering personnel evaluated the
event, was to remove the heater and to forbid anything from being plugged into the
control room outlets. All operators understood that nothing was to be plugged-in
anywhere in the control room until engineering personnel completed their review.
However, 3 days after the initial loss, the inspectors found that the Unit 2 and the Unit .3
unit supervisors were not aware that both control panels still had a power cord plugged
10
into a placarded outlet, and that on each unit the power cord.s fed unlabeled wall-outlet
type connectors near the feedwater panels. The human factoring of the power cord
situation was almost the same as the original power strip under the desk. Therefore, the
short-term corrective actions were incomplete.
At Dresden, a PIF is the first formal mechanism for requesting an operability
determination. However, the PIF about the instrument loss did not request an operability
determination. The PIF author and reviewer did not recognize that the operability of the
equipment was in question. Therefore, the inter-department communications failed.
Operations requested engineering to review the lighting circuit, and at least one shift
manager held a meeting with engineering staff to review these circuits. However,
operations personnel did not force. engineering staff to come to a rapid conclusion.
Discussions with operations staff 3 days after the event showed that the operations staff
thought that engineering personnel were evaluating the impact of :the loss, and that they
would inform operations personnel if the equipment was inoperable. However, the
engineering staff had not been directed to perform an operability evaluation; so they were
not actively considering equipment operability. Therefore, inter-department
communications continued to fail.
When the PIF was presented to the events screening committee, the presenter
suggested to the screening committee that only an apparent cause evaluation within
operations be done; the committee rejected the suggestion and directed that a root cause
evaluation be done (the root cause is a much more extensive and formal type of
investigation). The inspectors had discussed the seriousness of the event with members
of the events screening committee who directed that a root cause evaluation be
performed. The inspectors concluded that the corrective actions group was under
reacting by suggesting only an apparent cause evaluation confined to operations.
On June 4, 1998, following a meeting in which the inspectors questioned engineering
personnel regarding the operability of the PAM instrumentation, engineering personnel
informed operations staff that the post accident monitoring instrumentation was
inoperable. The operations staff then retroactively entered the TS LCO.
Section E4.1 contains additional discussions of the engineering response.
c.
Conclusions
Operations personnel declared Unit 3 TS instrumentation operable although the
instrumentation had been lost from the tripping of a Unit 2 lighting circuit. The operations
department personnel did not recognize that post-accident monitoring instrumentation
required by TS was shown to be inoperable by virtue of its nonsafety-related power
supply. Operations staff failed to communicate the significance of the issue in logs, in
PIFs, and in face-to-face turnovers. The operations staff did not force rapid resolution of
the issue.
11
07
Quality Assurance in Operations
07.1
Oversight of Startups
The inspectors reviewed the nuclear oversight reports made by the Quality and Safety
Assessment (Q&SA) department for reactor startups from forced outages D2F30 and
D2F31, and from refueling outage D2R15. The inspectors also reviewed reports made by
Q&SA of shutdown risk for D2R15, outage activities during D2R15, and other activities by
operations staff. These activities took place since January of 1998. The inspectors also
monitored the activities of the Q&SA personnel in the control room during the startups.
The startup reports were informative. The reports documented direct observation of
activities, and drew reasonable conclusions from the observations. Auditors from Q&SA
could explain the findings and the significance to the inspectors. Issues identified by
Q&SA auditors during the most recent startup were relevant and showed good attention
to detail by the auditors.
Overall, the Q&SA oversight of operations was good.
08
Miscellaneous Operations Issues (92700)
08.1
(Closed) LER 50-249/95016-00: Failure of High Pressure Coolant Injection Low Pressure
Surveillance Due to Exhaust Drain Pot High Level Alarm Relay- Switch Failure. On
September 11, 1995, during the TS required low pressure surveillance test, the HPCI
system exhaust drain pot high-level alarm remained in an alarm state much longer than
. expected. The licensee inspected and flushed system flow paths, but found no
- abnormalities. The licensee also investigated the alarm relay and level switches and
found no abnormalities. In the absence of anything definite, the licensee replaced the
drain pot bypass valve (3-2301-32) and enlarged the orifice downstream of the 3-2301-32
from 3/16" to 7/16" to allow for a greater overall system flowrate, and replaced the drain
pot level switch and relay.
The problem has not recurred. This item is closed.
08.2
{Closed) Violation (VIO) 50-237/249/98007-01: Failure to designate all M&TE records as
QA records and failure to have a 5 year retention period.
The licensee contested the notice of violation (NOV) by docketed letter dated May 14,
1998. The licensee sent the Region Ill office information that had not been provided
during the inspection. On that basis the NRC rescinded the violation. This item is
closed.
08.3
Commitment Review for the March 28. 1997. 10 CFR 50.54<0 Letter
a.
Inspection Scope (71707)
On March 28, 1997, the licensee sent the NRC its response to the NRC's request for
information under 10 CFR 50.54(f) regarding safety performance at ComEd. Part of the
response contained various commitments. The inspectors reviewed the status of those
commitments.
12
b.
Observations and Findings
Note that throughout this report, the *item numbers correspond to the licensee's internal
tracking system. Each item discussed below was statused in the licensee's monthly
report and was considered closed by the licensee.
Item No. 105 Provide status of the formalized business planning process at
Dresden Station.
Dresden station management established a formalized business planning process. The
formalized business plan led to the development of the 1997 Operational Plan. This
operational plan contained goals that the licensee tracked using their Nuclear Tracking
System (NTS). The inspectors noted that the monthly status of the NTS items was added
to the Dresden Station Business Plan Summary Status.
Item No. 107 Provide status regarding the implementation of the comprehensive set of
actions that addressed the deficiencies identified by the Independent Safety
Inspection (ISi).
The process of developing a comprehensive set of actions to address the deficiencies
identified by the ISi has been completed. In a letter from Dresden to the NRC dated
February 26, 1997, the licensee provided a detailed response to the identified.
deficiencies.
Item No. 108 Provide status regarding Dresden's implementation of Phase I of the
ComEd standard corrective action process.
The Dresden Station carried out Phase I of the new ComEd Standard Corrective Actions
Process. The inspectors noted that licensee documentation indicated that the licensee
provided training to site personnel on problem identification and root cause analysis.
Additionally, Corporate Procedures NSWP-A-15, "ComEd Nuclear Division Integrated
Reporting Prog~am," Rev. 1, May 5, 1997, and NSWP-A-16, "Effectiveness Review,"
Revision 1, May 5, 1997, had been approved and implemented at Dresden.
Item No. 109 Provide status regarding Dresden's implementation of Phase II of the
standard corrective action process.
Documents provided by the licensee showed that the licensee had carried out Phase II of
the Standard Corrective Action Process at the site. The licensee had provided training to
all site personnel.
Item No. 110 Provide status and evidence that Dresden Administrative Procedure
(OAP) 02-27, "The Integrated Reporting Process," provides more concise direction for
Performance Improvement Form initiation and provide evide.nce and examples of
OAP 02-27 regarding Maintenance Preventable Failures (MPF).
The Dresden Administrative Procedure (OAP) 02-27, "The Integrated Reporting
Process*(IRP)," was deleted at the Dresden Station and replaced by NSWP-A-15,
"ComEd Nuclear Division Integrated Reporting Program." The program provided specific~
detailed guidance 'about when a PIF was to be initiated. The guidance also had
13
examples of equipment failure that addressed Maintenance Preventable Functional
Failures (MPFF). The review process screened the PIF for MPFF. The site's PIF
initiation training appeared to be complete.
Item No. 111 Provide status and evidence regarding the training of Dresden site
personnel regarding the revised initiation criteria and provide evidence of the success of
- the revision.
The licensee provided training on NSWP-A-15 requirements and guidance for PIF *
initiation to Dresden personnel and contractors. Dresden management used the
increased number of PIFs initiated as one measure of the successful training and the
effectiveness of the revision.
Item No. 112 Provide status and evidence of the success of the issuance of Nuclear
Engineering Procedure (NEP) 10-3, "Disposition of Design Basis Discrepancies," issued
on January 20, 1997.
All engineering personnel were trained on NEP-10-3 and the licensee used the doubling
of the number of PIFs in design basis discrepancies as a measure of the success of the
revised procedure and training.
.
Item No. 113 Provide status of the monitoring of PIF initiation levels at Dresden that
ensure problem identification and reporting continue.
The licensee continued to monitor the number of PIFs initiated each month. The number
has been normalized by using the number of PIFs per 1000 man-hours worked. The *
number of PIFs initiated each month continued to increase during the previous 2 years.
The licensee considered the continued increase in the PIFS initiated as a sign the training
and procedure revisions were successful.
Item No. 114 Provide status and examples where the radiation protection (RP) has
performed error trending and performance quality self assessments.
The licensee has assigned an individual with significant experience in RP to.be
responsible for error trending and conducting performance quality self assessments of
RP. The licensee *performed assessments and assigned corrective actions. Additionally,
root cause analyses of errors were performed and approved by the licensee's corrective
action review board (CARB). To ensure thatcorrective actions implementation were
effective, the licensee performed quality effectiveness reviews. Dresden management
was trending the human performance errors docum_ented in the Pli= system monthly.
c.
Conclusions.
The licensee's Nuclear Tracking System (NTS) indicated the above items were
. completed or fulfilling the requirements. The status and monitoring information were
being provided as directed. * The monthly reports appeared to receive evaluation of the
information submitted by the various individuals and groups. The number of PIFs initiated
. each month had continued to increase.
14
II. Maintenance
M1
Conduct of Maintenance
M1 .1
General Comments
The inspectors monitored routine maintenance actives through direct observation,
- attendance at maintenance and operations meetings, and reviewed the results of
maintenance.
No concerns were identified with jobs directly observed. The mechanics and technicians
followed their procedures and work instructions, and correctly documented the results.
Issues discussed at station management meetings showed that the licensee was placing
importance on emergent equipment problems commensurate with operations' requests,
and that the licensee was actively using its planning procedures to assign work priorities.
Review of issues identified in PIFs did not typically reveal significant rework or
maintenance errors.
Nonetheless, as described in Section M2.1 ofthis 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 was made unavailable after maintenance, or could not be
restored to operable following maintenance.
b.
Observations and Findings
On June 10, 1998, the Unit 2 emergency diesel generator tripped on reverse power
during a routine surveillance test. The licensee investigated and found a disconnected *
wire in the emergency diesel generator's fuel governor. The wire was the same wire that
had previously caused electrical grounds due to the wire rubbing on moving parts. The
licensee concluded that the wire had not been properly secured after some previous
maintenance work. The previous work was detection and correction of an electrical
ground in the same governor caused by the same wire. The licensee believed that the
work to address the previous electrical grounds missed an opportunity to secure the wire
and by that prevent the Unit 2 emergency diesel's trip. Pending 'review of the associated
work packages, this is an inspection follow-up item (IFI 50-237/98019-02) .
. Electro-Hydraulic Control System
As discussed in Section 02.1 i on-line work performed on the 3A EHC system resulted in
a turbine trip and a reactor scram during system restoration .
15
The licensee's investigation into the cause found that the pump's vent valve had failed
shut. The investigation also found that no preventive maintenance or other surveillance *
test was performed on the vent valve, so there was no opportunity to discover the failure.
Security Diesel Generator
The security diesel started automatically following equipment failures that failed the
normal source of security equipment power. The security diesel subsequently tripped
twice while loaded. The trips were eventually tracked down to material condition
problems with exhaust temperature sensor wells.
The licensee failed to detect the failure mechanism during routine maintenance and
testing, and failed to identify the cause of the trip after the first automatic trip. Final
- review of the security diesel failures will be completed after receipt of the associated
security event reports.
c.
Conclusions
The material condition of equipment affected station operation and availability. A failure
in the electro hydraulic control pump's vent valve led to a reactor scram. An emergency
diesel generator failed a surveillance test due to a loose wire in the governor system.
The security diesel generator started due to failed electrical distribution systems, and then
twice tripped off due to material condition.
M2.2
Potential Common Mode Failure of Containment Cooling Service Water Pumps
a.
Inspection Scope (62707)
On June 28, 1998, the 3C containment cooling service water (CCSW) pump failed while
- in service. The failure symptoms were consistent with foreign material intrusion into the
pump. The inspectors reviewed the licensee's ~esponse to the event.
b.
Observations and Findings
Section 9.2 of the UFSAR stated that the CCSW system provides cooling water for the
containment cooling heat exchangers, during both accident ard nonaccident conditions.
Four pumps.are available per unit for a total of eight pumps. All of the CCSW pumps*
take a suction from bay-13 in the 2/3 cribhouse.
On June 28, 1998, operators started the 3C CCSW pump for CCSW vault room cooling.
An operator noted that the pump was noisy and that the pump parameters were abnormal
(flow of 2200 gpm vice the normal flow of 3500 gpm and discharge pressure of 70 psi
vice the normal pressure of 190 psi). The operators secured the pump, declared it
inoperable, and entered the appropriate TS LCO. The licensee disassembled the pump
and found several pieces of drift wood and walnut halves in the pump. The pump was
successfully returned to service on July 1, * 1998. Operators verified the operability of the
remaining Unit 3 CCSW pumps.
Because of the problems associated with the 3C CCSW pump, operators tested the
Unit 2 CCSW pumps: On July 1, 1998, the 28 CCSW pump showed indications of
16
cavitating. The licensee disassembled the pump and also discovered debris in the pump
impeller and casing. While 28 CCSW pump repairs were ongoing, the operators
successfully verified the operability of the remaining Unit 2 CCSW pumps. The
28 CCSW pump was demonstrated operable and successfully returned to service on
July 2, 1998.
The licensee documented the occurrences in PIFs 01998-04183, 01998-04251, and
01998-04272. The licensee also initiated a prompt investigation; the results of the
- prompt investigation determined that the wood entered bay-13 when the bay inlet screens
were removed for routine cleaning on May 22, 1998. The station manager stated that the
bay inlet screens would not be removed to support further maintenance activities unti.1 a
solution was implemented for the foreign material intrusion concern. The inspectors will
follow resolution of this matter during routine maintenance and engineering inspections.
There have been other instances of.foreign material intrusion into the CCSW pump *
systems. For example, Inspection Report 96004, Section M4.1, documented intrusion of
a t::.shirt into the CCSW system. The t-shirt came from work on the 2/3 diesel fire pump
located directly over the bay. Inspection Report 96002 issued a violation for failure to *
identify and take prompt corrective actions for Containment Cooling Service W~ter
(CCSW) foreign material problems that occurred since 1994, and that resulted in the
failure of the "2A" CCSW pump in March 1996. These examples were all greater.than
2 years old. However, the current examples indicate close attention is needed *by the
station to control foreign material intrusion into the safety-related pumps' suction bay.
c.
Conclusions
A potential common mode failure impacted the operability of the safety-related CCSW
pumps. The failure occurred during the conduct of routine maintenance activities. Once
the problem was identified, the station responded aggressively to verify operability of the
remaining CCSW pumps.
M4
Maintenance Staff Knowledge and Performance
M4.1
Core Spray System Maintenance
a.
Inspection Scope (62707)
The inspectors monitored portions of the licensee's work on the 3A core spray system.
b.
, Observations and Findings
No concerns were identified with jobs directly observed. The mechanics and technicians
followed their procedures and work instructions, arid correctly documented the results.
On July 8, 1998, the maintenance staff completed work on the 3A core spray system.
This was the first tirne that the work had been performed outside a refueling outage.
Operators vented the. system and started the 3A Core Spray System pump to verify
system operability. The 3-1402-38A valve (Core Spray Minimum Flow Valve)
unexpectedly throttled closed, reopened, and then closed again. Operators secured the
pump due to the unexpected response of the minimum flow valve. The licensee
17
investigated and concluded that a slug of air had been entrained in the core $pray system-
and caused a pressure perturbation that in tum caused the minimum flow valve to cycle.
Station personnel first attempted to backfill the minimum flow valve's sensor to remove
any air still remaining in the system, but the minimum flow valve still cycled. Operators
then vented the system while there was residual pressure in the lines following a pump
start and stop. This method was successful and the core spray system was made
operable on July 9, 1998.
The core spray work was completed within the TS time limits. However, the core spray
system was unnecessarily inoperable for about three shifts due to the difficulties
encountered during system restoration following on-line maintenance activities.
Inspection Report 98003 documented a previous instance where performance of an
activity with the reactor on-line that had previously been performed in an outage resulted
in unexpected consequences. The result was a reactor scram on January 13, 1998.
c.
Conclusions
Maintenance on the core spray system was performed on-line for the first time instead of
during a refueling outage. Problems venting the .core spray system following the
maintenance led to additional unplanned core spray system outage time.
Ill. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1
Material Condition Review Team
a.
Inspection Scope (37551)
The station established a team to improve the material condition of 26 selected systems
with the intent of preventing scrams and lost electrical generation. The inspectors
observed early team effects and discussed the team's progress with selected individuals.
b.
Observations and Findings
The Dresden Station Site Vice President chartered the team to improve the material
- condition of selected systems to ensure that the material* condition .of these systems did
not cause a scram, derate, or a significant challenge to plant operators. The team was
composed of individuals from various departments and was staffed to work 7 days a
week for 8 weeks. The team was to identify short term improvements and to provide
input to Dresden's 1-year and 3-year material condition improvement plans.
The inspectors noted that the team's reviews included vendor information, work history,
operating experience, and other appropriate sources of information. The team provided
daily progress briefings to station senior managers and received feedback on minor
corrections the team needed to make to generate the expected results. The team
- completed review of the electro hydraulic control system, the high pressure coolant
injection system, and the circulating water system by the end of the inspection period.
18
c.
Conclusions
The development and charter of the team were a positive initiative. The team's reviews
had the potential to improve plant material condition and to reduce significant challenges
to the operators.
E4
Engineering Staff Knowledge and Performance*
E4.1
Loss of Control Room Indications (Unit 3)
a.
Inspection Scope (71707, 37551)
On June 1, 1998, some Unit 3 control room indications were deenergized when an
operator turned on a space heater plugged in the control room. The inspectors assessed
the licensee's response to the event,* and the circumstances that led to the interaction
between a wall outlet and TS instrumentation.
The reviews included monitoring of the licensee's investigation, review of the Master
Equipment List, review of UFSAR Sections 7.5 and 8.3, and .discussions with personnel.
The licensee's root cause report was also reviewed.
b.
Observations and Findings
Section 04.2 of this report described the event and the response by operations.
Engineering staff members were assigned to review the circuits and determine what
instrumentation was supplied by what source. The engineering staff was also chartered
to review the appropriateness of using the specific instruments for the post-accident
monitoring function and to determine the root cause of the event.
Electrical Distribution
The heater was plugged into an ordinary power strip, along with a computer and a radio
charger. The power strip was plugged into an outlet, and the outlet was labeled as
requinng unit supervisor permission to use. However, the placard was at the outlet, far
under a desk, arid only readable by crawling under the desk.
The engineers found that the wall outlet was energized by ~ nonsafety-related regular
lighting circuit. The same circuit also provided outlets being used by recently installed
- temporary scram monitoring instrumentation. The instrumentation was on mobile carts
and plugged into wall outlets inside the control panels. The outlets had caution placards
similar to the one under the operators' desk.
UFSAR, TS, and DATR and Regulatory Guide 1.97
Technical Specification 3.2.F, "Accident Monitoring," required, in part, that two channels
of drywell pressure narrow range and two channels of torus pressure be operable.
Dresden Administrative Technical Requirements (DATR) 3/4.16, "Post Accident
Monitoring Instrumentation Panel Locations, Ranges, and EPNs [electronic part
numbers]," listed the following channels as required by the TS:
19
Unit 3 Torus
903 - 5
-2.45 to 5 pisg
Pressure
+-----+------+-------11
Unit 2 Torus
Pressure
1-------+-----+------+-------1
The breaker overload caused, among other losses, a loss of Pl 3-1640-5 (drywell
pressure narrow range) and of Pl 3-1640-4 (torus pressure). These indicators were
green LED-type digital displays, and will be called the digital displays throughout the
remainder of this report.
Section 7.5.1, "Post-Accident Monitors," of the UFSAR stated:
"Certain instruments have been designated as post-accident monitors, and
as such have been determined to comply with Regulatory Guide (RG) 1. 97
[Rev. 2, 12/1/80]. These instruments are identified in the Master
Equipment List (MEL)."
The section of the UFSAR also stated that drywell pressure and suppression chamber
(torus) pressure were Type A variables per RG 1.97. Type A variables are those
variables to be monitored that provide the primary information needed to permit the
control room operating personnel to. take the specified manually controlled actions for
which no automatic control is provided and that are required for safety systems to
accomplish their safety functions for design basis accident events. The UFSAR further
stated that instruments monitored by these variables meet the intent of Category 1
requirements per RG 1.97, or deviations from these requirements have been justified.
Regulatory Guide 1. 97 stated that the instrumentation should be energized *from station
standby power sources as provided in RG 1.32, "Criteria for Safety-Related Electric
Power Systems for Nuclear Power Plants." The loss of instrumentation from tripping of a
regular lighting circuit showed that the Unit 3 digital displays were not powered from
standby power, but rather from a regular nonsafety-related lighting circuit.
The MEL information about Pl 3-1640-4 and Pl 3-1640-5 did not match the Dresden
Administrative Technical Requirements. Specifically, information in the electronic work
20
.'
control system (EWCS) MEL database for Pl 3-1640-4 and Pl 3-1640-5 stated, "RG 1.97
Cat/Type: N." That meant that the MEL did not show that Pl 3-1640-4 and Pl 3-1640-5
were being used by the DATRs to satisfy RG 1.97 requirements.
Engineering Response
Engineering personnel were assigned to review the circumstances of the loss of
instrumentation. On June 3, the shift manager met with engineering personnel. The
meeting concluded with the engineering staff being assigned to walk down the
instruments. The meeting did not discuss operability. The inspectors noted that nuclear
oversight also attended the meeting, but the oversight inspector did not question the lack
of operability discussion.
By the afternoon of June 4, 1998, engineering staff held a meeting with operations staff to
discuss the progress. At the end of the meeting, when operability was clearly not being
pursued, the inspectors questioned licensee personnel about equipment operability
because the PAM instrumentation did not meet RG 1.97 power supply.guidance.
Licensee personnel replied that they were not going to do an operability evaluation.
Subsequently the inspectors raised the concern in a meeting with the plant senior
management. Shortly after, the engineers told the operators that the PAM
instrumentation was inoperable.
Resolution
The licensee eventually determined that the green digital instruments were not qualified
as safety-related. Therefore, Unit 2's PAM instruments were also inoperable. Operation*s
complied with the appropriate LCOs. The licensee restored instruments from the
abandoned atmospheric containment atmosphere dilution (ACAD) system, and changed
the DA TRs to use the ACAD instruments.
Recent Opportunities to Identify the Issue
Within the past year, there were opportunities to identify this issue. On May 22, 1997, an
individual from regulatory assurance wrote an engineering request (ER 9702363) to
"validate and add list of Reg Guide 1.97 instruments to UFSAR." On April 28, 1998, the
ER was rejected, and no feedback was provided to the requesto(. The same person then
wrote PIF D1998-03306, "Lack of controlled list for Reg Guide Instrumentation," to restate
- the request and to document that the engineering request was rejected without any
justification. The PIF was assigned an apparent cause evaluation (ACE), but the actual
loss of instrumentation happened before the ACE was due.
Root Cause Report
- Licensee personnel completed root cause report number 249-200-98-00700, Rev. 0,
"Control Room Indications Lost when Lighting Cabinet Breaker Tripped," and Nuclear
Operations Notification (NON) DR 98-43 Supp-1, "Lost Control Room Indications when
. heater was plugged into outlet in Control Room." The root cause report concentrated
only on the history of how the indications became required post-accident monitoring
equipment. The root cause report attempted to answer the question of why the Dresden
Administrative Technical Requirements did not specify the correct post-accident
21
. '
instruments. The inspectors concluded that the root cause report should have addressed
why engineering and operations failed to recognize inoperable equipment and inadequate
design and did not enter required TS LCOs until multiple prompts by the NRC.
Many issues were missed by the root cause evaluation. It did not discuss the failures in
communications, control room logs, and face-to-face turnovers. The evaluation did not
discuss the slow reaction by engineering and operations. It did not discuss caution
placards over the outlets, or the use of extension cords and power strips. It did not
discuss previous events and the history of why the caution cards were placed. It did not
discuss how operating personnel were not aware of what was plugged in 3 days later. It
contained fundamental factual errors. For example, it stated that instruments were lost
when the heater was "plugged in." In reality, the heater was already plugged in, the
operator just turned the heater on. This was significant because of the caution placard
telling the operator not to use the outlet without permission.
The root cause report stated. that the heater overloaded the circuit. In reality, the heater
was just o*ne part of the load on the circuit. The scram monitoring instrumentation was
also plugged into placarded outlets. The root cause report was silent about the adequacy
of the reviews completed before the scram monitoring instruments were installed.
The root cause report presented information that could not be independently
substantiated. For example, the root cause report stated that a contributing cause was
"Dresden Station had low standards with respect to problem identification as evidenced
by generation of ER 9702363 instead of a Problem Identification Form (PIF). The cause
of this deficient culture is indeterminate due to historical nature of the issue." The
inspectors determined that no one had interviewed the person who generated the ER.
The individual was surprised to see that the root cause report listed his generation of an
ER instead of a PIF last year as a contributing cause. Furthermore, the individual
maintained that an ER was the appropriate mechanism for making such a request, and
was not from "low standards," but instead was the proper procedurally-driven way of
resolving issues.
The NON repeatedly downplayed the issue with statements like the instruments "may be
referenced during mitigation of accidents, but are not required." The statement "are not
required" was clearly incorrect because the TS and DATR required the instruments. As a .
consequence, the NON*did not.transmit the significance of the issue to the other ComEd *
station personnel.
Regulatory Requirements
Criterion XVI of Appendix B to 10 CFR Part 50 states that measures shall be establjshed
~o assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and nonconformances are promptly
identified and corrected.
Contrary to this, the licensee failed to assure the deficiencies in the source of power for
post acCident monitoring instrumentation were promptly identified; the failure of the power
source on June 1, 1998, demonstrated that the power source was not safety-related, but
the licensee failed to identify this until June 4, 1998. The failure to identify the deficiency
promptly was a violation of Criterion XVI of Appendix B to 1 O CFR Part 50
22
,I
(VIO 50-249;98019-03). Consequently, the licensee prematurely exited an LCO on
June 1, 1998; on June 4, 1998, the licensee retroactively reentered the LCO.
c.
Conclusions
The PAM instrumentation was lost when a nonsafety-related circuit tripped, revealing that
instruments required by TS were powered by nonsafety-related circuits. The selected
instruments did not meet the requirements specified in the UFSAR. Engineering
personnel reviewing the loss of PAM took 3 days to conclude that the instruments were
inoperable due to the use of nonsafety-related power.
The root cause report performed by the licensee contained factual errors and information
that could not be proven. The root cause report failed to discuss significant issues. *
Miscellaneous Engineering Issues (92902)
E8.1
(Closed) Unresolved Item (URI) 50-237;249/98014-01: Incorrect annunciator setting for
Main Steam Line Radiation Monitors (Unit 2). The subject URI discussed a licensee-
identified situation where a design error resulted in the incorrect setting for the Main
Steam Line Radiation Monitor alarm setting.
During the Unit 2 refueling outage (02R 15) the licensee identified a modification to
remove the Main Steam Line Radiation Monitor trip setpoint from the reactor protection
system.* The modification package incorrectly specified an alarm setpoint of 3.0 times
normal background rates with hydrogen addition in s.ervice vice the required 1.5 times
normal background. The license condition stated, "The licensee shall change the
setpoints for the Main Steam Line Radiation Monitor and Offgas System Radiation
Monitor alarms to 1.5 times the normal full power N-16 background (with hydrogen
addition) dose rates." The licensee documented the occurrence via problem identification
- forms 01998-02842 and 01998-02877. The licensee concluded that Unit 2 was out of
compliance with the licensed condition.
Unit 2 startup from the refueling outage commenced on April 15, 1998, and the licensee
discovered the setpoint error on April 17, 1998. Following the Unit 2 reactor scram on
April 20, 1998, the licensee corrected the alarm setpoint. This non-repetitive, non-willful,
licensee-identified and corrected violation is being treated as a Non-Cited Violation,
consistent with Section Vll.B.1 of the NRC enforcement policy (NCV 50-237;98019-04).
This item is closed.
E8.2
(Closed) URI 50-237:249/96009-07(0RP}: Acceptability of interchanging compression
fitting hardware. The license identified no cracks or failures due to compression fittings
established with mixed components .. The licensee also.revised Procedure NSWP M-02,
"Fabrication and Installation of Piping and Tubing," to specify that matched* sets of fittings
be used in new or rebuilt applications. The inspectors determined that no regulatory
23
,I
requirements were violated by interchanging components from different fitting
manufacturers. This item is closed .
E8.3
(Closed) URI 50-237/249-95015-07: Drawing errors. This URI was to review the
licensee's drawing control program improvements. On August.31, 1995, the licensee
published the results of an investigation into configuration management. The
investigation identified an inconsistency between field configuration and drawing
configurations, and an ineffective process to incorporate field corrections into drawings.
Corrective programs that resulted from the licensee's investigation included drawing
walkdowns by the system engineers, design change request backlog reduction, review of
24,000 design changes to verify installed conditions, and drawing re-drafting.
The investigation also recommended that an effectiveness review be performed. The
. inspectors* asked for the effectiveness review, and the licensee determined that no
effectiveness review for drawing errors was ever done.
Criterion Ill of Appendix B to 1 O CFR Part 50 required the licensee to translate the plant
design into drawings, specifications, and procedures. Contrary to this, the
NRG-inspection conducted on December 19, 1995, 1hrough February 13, 1996, identified
an example of a drawing that did not reflect the plant. The licensee's initial corrective
actions addressed the identified problems and rechecked the drawing and related
drawings likely to contain similar errors. From these reviews, the licensee identified and
corrected additional drawing control problems. The identified violation was of minor
significance and is not subject to formal enforcement action.
E8.4
(Closed) Apparent VIO 50-237196012-01; 50-249/96012-01: Failure to provide adequate
protection from hot electrical shorts to ensure operation of equipment needed to achieve
and maintain hot shutdown. This item was also tracked under EA#s96-388, 96-389,
and 96-390. In a letter from the Region Ill Regional Administrator to the ComEd
President of the Nuclear Generation Group and Chief Nuclear Officer dated
December 30, 1997, the NRC determined that a violation occurred. However, the letter
stated that Enforcement Discretion was used in assessing the severity of .the violation,
and that no response was necessary. This item is closed.
E8.5
(Closed) Apparent VIO 50-237/249-96014-01: Failure to perform testing of modifications
performed to Unit 2/3 control room HVAC system. This item was also tracked under
EA# 96-532. In a letter from the Region Ill Regional Administrator to .the Dresden Station
- Site Vice President dated May 21, 1997, the NRC determined that a Severity Level Ill
violation occurred. Due to actions taken by the licensee, no civil penalty was assessed
and no response was necessary. This item is closed.
E8.6. (Closed) VIO 50-237/96005-03; 50-249/96005-03: Corrective Action Violation Associated
with Comer Room Steel. This violation was associated with Enforcement Action 96-115.
The licensee repaired the low pressu're coolant injection comer room structural steel to
meetthe requirements of the UFSAR. The licensee also reviewed other outstanding
design issues and provided training to design and system engineers on how to handle
UFSAR discrepancies. This item is closed.
24
E8.7
(Closed) VIO 50-237/96005-04; 50-249/96005-04: Failure to Submit a Licensee Event
Report Associated with Comer Room Steel. This violation was associated with
Enforcement Action 96-115. The licensee verified that its Operability Manual was using
the latest reportability guidance and ,provided training to its employees regarding the need
to report non conforming conditions. This item is closed
E8.8
(Closed) Escalated Enforcement Item CEEI) 96-114-01013: Inadequate Corrective
Actions For Structural Steel. This EEi number actually applied to Quad Cities rather than
Dresden. The Dresden EEi for the comer room steel issue was96-115. Both sites
tracked the violations under the original report number (96005-03 and -04.) Since this
item was merely a tracking device, it is now closed ..
E8.9
(Closed) EEi 96-114-01024: Failure to Report Condition Outside Design Basis (Corner
Room Steel). This EEi number actually applied to Quad Cities rather than Dresden. The
Dresden EEi for the comer room steel issue was96-115. *Both sites tracked the
violations under the original report number (96005-03 and -04.) Since this item was
merely a tracking device, it is now closed.
E8.10 (Closed) VIO 50-237/97003-01 (DRS): Violation of 10 CFR 50.59 for not performing a
safety evaluation for the undocumented installation of a pump in the Unit 2 torus
basement. In response to the violation, the licensee committed to remove the pump,
thereby restoring the configuration to that documented in the Updated Final Safety
Analysis Report (UFSAR). The inspectors toured the Unit 2 torus basement and verified
that the pump had been removed. This item is closed.
E8.11 Core Operating Limits Report
- On April 25, 1998, the inspectors requested that the licensee provide the core operating
limits report (COLR) for Unit 3 Cycle 15. The inspectors made the request because the
NRC had no record of receipt of the Unit 3 Cycle 15 core operating limits report.
In response to the NRC's inquiry, the licensee investigated and found that the following
COLRs were not submitted: the mid-cycle for Unit 3 cycle 15 dated September 19, 1997,
the beginning-of-cycle for Unit 3 cycle 15 dated June 13, 1997, the first mid-cycle for
Unit 2 cycle 15 dated June 24, 1997, and the second mid-cycle dated September 19,
1997.
By letter dated June 22, 1998, from the Dresden Station Site Vice President to the
USNRC Document Control Desk, the licensee identified the missed submittals and noted
that the missed submittals were in noncompliance with TS 6.9.A.6.c; the letter also
transmitted the missing COLRs. The submittals were considered acceptable by the NRC.
Technical Specification 6.9.A.6.c., stated that the core operating limits shall be
determined so that all applicable limits of the safety analysis are met, and "the Core
Operating Limits Report, including any mid-cycle revision or supplements thereto, shall be
provided upon issuance, for each reload cycle, to the NRC Document Control Desk with
copies to the Regional Administrator and Resident Inspector."
Contrary to the above, the licensee failed to provide to the NRC the Core Operating Limits
Reports for the beginning-of-cycle for Unit 3 Cycle 15, the Unit 2 mid-cycle revisions for
25
J
June 1997 and September 1997, and the Unit 3 mid-cycle update for September 1997.
This violation constitutes a violation of minor significance and is not subject to formal
enforcement action.
-
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1
General Comments (71750)
During routine inspections in radiologically controlled areas, the inspectors assessed the
performance of the licensee.
Overall, the licensee's radiation protection staff enforced the plant's radiological: control
standards. The licensee continued to use personnel functioning as greeters"to assure
that workers entering the radiologically controlled area were aware of dose rates and
administrative protection requirements.
52
Status of Security Facilities and Equipment
S2.1
Security Diesel and Power Supply (71750)
On May 28, 1998, an electrical system perturbation caused a loss of the normal feeds for
security and safeguards equipment, so the security diesel generator started automatically.
The security diesel tripped on indicated high temperature in the evening after running fine
during the hottest part of the day. The machine was restarted, and it ran until almost the
same time the next evening, then tripped again on high temperature. Before the second
trip, t~e machine had been monitored, and no temperature anomalies noted. The engine
was not restarted and the licensee used a temporary transformer to supply power to the
security systems.
The temperature indication was in calibration and tested satisfactorily. There had been
no recent work on the diesel that could have impacted the probe. The licensee was* *
unable to determine the reasons for the high temperature trips.
On June 1 O, 1998, the security diesel generator tripped again during a test run. A vendor
representative who was monitoring the test run suggested that the temperature sensor be
abandoned in place and replaced with a different m*odel. The licensee followed the
suggestion and subsequently the diesel ran successfully.
The inspectors discussed the diesel's performance and the licensee's troubleshooting
activities with the diesel system engineer. The engineer indicated that the
troubleshooting and investigations.had included review of vendor instructions. The
engineer indicated that the failed sensor was supposed to last for the life of the diesel,
and that there was no information from the vendor that suggested that the diesel be
modified for use of a different temperature probe. The vendor stated that the
temperature probes did not have a generic failure mechanism.
26
J
c.
By the end of the inspection period, the licensee had submitted Security Event Report
(SER) 98-S02. The SER stated that the cause of the event had not been determined, but
that a supplement to the SER would be submitted after the licensee's investigations were
complete. Additional review of the multiple failures of the security diesel generator will be
tracked through the associated SERs.
Conclusions
The security diesel failed twice when called upon and once during a test run due to
material condition. The licensee took the appropriate steps to troubleshoot the failures,
including review of vendor information and* consultation with the vendor.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of license management at
the conclusion of the inspection on July 14, 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 .
27
R. Kelly
K. Housh
C. Richards
B. Kobel
P. Planning
D. Winchester
S. Barrett
L. Aldrich
M. Pacilio
R. Fisher
P. Swafford
F. Spangenberg
P. Chabot
W. Lipscomb
J. Kocek
T. Phillips
S. Kuczynski
. PARTIAL LIST OF PERSONS CONTACTED
ComEd Regulatory Assurance NRC Coordinator
ComEd Nuclear Oversight NO Engineering Assessments
ComEd Nuclear Oversight Assessment Manager
ComEd Unit 1 Engineering Org. Reg. Compl. Eng.
ComEd Plant Eng. Supt.
ComEd Nuclear Oversight Manager
ComEd Operations Manager
ComEd Radiation Protection Manager
ComEd Work Control and Outage Manager
ComEd Maintenance Manager
ComEd Station Manager
ComEd Regulatory Assurance Manager
ComEd Engineering Manager
ComEd SVP Assistant
ComEd Supply Manager
ComEd Radiation Protection Technician
ComEd Operations Shift Technical Supervisor
28
- (
- '
INSPECTION PROCEDURES USED
IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
Onsite Engineering
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support Activities
IP 92700:
Onsite .Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92902:
IP 92903:
Followup - Engineering
Followup - Maintenance
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-237;249/98019-01A, B
50-237/98019-02
50.-249/98019-03
50-237/98019-04
Closed
50-237;249/98019-01A, B
50-237/98019-04
. 50,-237;279/98007-01
50-249/95016-00
50-237;249/98014-01
50-237;249/96009-07
50-237;249/95015-07
50-237;249/96012-01
50-237;249/96014-01
50-237;249/96005-03
50-237;249/96005-04
50-237/97003-01
96-114-01013
96-114-01024
Discussed
None.
IFI
LER
APVIO
APVIO
EEi
EEi
Failure to Log Entry into LCOs
Failure of Unit 2 Emergency Diesel Generator
Failure to Perform Prompt Corrective Actions for
Post-Accident Monitoring Instruments
Failure to follow License Condition for Main Steam
Line Radiation Monitor Settings
Failure to Log Entry into LCOs
Failure to follow License Condition for Main Steam
Line Radiation Monitor Settings
records and failure to have a 5-year retention period
Failure of High Pressure Coolant Injection Low
Pressure Surveillance
Incorrect Annunciator Setting for MSL
Acceptability of interchanging compression fitting*
Drawing errors
Failure to provide adequate protection fron:i hot
electrical shorts *
Failure to perform testing of modifications
performed to HVAC system
Corrective action violation associated with Comer
- room steel
Failure to submit LER
Not performing safety evaluation for undocumented
installation of pump
Inadequate corrective actions for structural steel
Failure to report condition outside design basis
29
ccsw
CFR
DATR
DES
DGP
DIS
DOA
DTS
EPN
EWCS
IFI
LCO
LER
MEL.
NCAD
NSO
NTS
oos
TS
LIST OF ACRONYMS USED
Atmospheric Containment Atmosphere Dilution
Apparent Cause Evaluation
Containment Cooling Service Water
Code of Federal Regulations
Dresden Administrative Procedure
Dresden Administrative Technical Requirements
Dresden Engineering Surveillance
Dresden General Procedure
Dresden Instrument Surveillance
Dresden Operating Abnormal
Dresden Operations Surveillance
Dresden Technical Surveillance
Electrical Maintenance Department
Electronic Part Number
Electronic Work Control System
High Pressure Coolant Injection
Inspector Followup Item
Instrument Maintenance Department
Limiting Condition for Operation
Licensee Event Report
Master Equipment List
Nitrogen Containment Atmosphere Dilution
Nuclear Station Operator
Nuclear Tracking System
Out-of-Service
.
Post-Accident Monitoring *
Problem Identification Form
Regulatory Guide
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
30