ML17180A748
| ML17180A748 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 05/06/1994 |
| From: | Langstaff R, Shafer W, Vanderniet C, Walker H, Yin I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17180A746 | List: |
| References | |
| 50-237-94-03, 50-237-94-3, 50-249-94-03, 50-249-94-3, NUDOCS 9405160302 | |
| Download: ML17180A748 (27) | |
See also: IR 05000237/1994003
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-237/94003(DRS); No. 50-249/94003(DRS)
Docket Nos. 50-237; 50-249
Licenses No. DPR-19; No. DPR-25
Licensee:
Commonwealth Edison Company
Executive Towers West III
1400 Opus Place - Suite 300
Downers Grove, IL 60515
Facility Name:
Dresden Nuclear Power Station - Units 2 and 3
Inspection At:
Dresden Nuclear Power Station, Dresden, IL
Inspection Conducted:
February 28 through April 5, 1994
Inspectors:
JfL.. /fr /2 / f' ~
......
ri. GWiJ kef:~r
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NRC Consultants: J. T. Haller (Parameter, Inc.)
~s-1?1t
D e /
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Date
5/6/J;J
Date
5!tc/£<1
Date
D. C. Prevatte (Powerdyne Corporation)
Observer:
L. A.
Love~Tedjoutomo (Atomic Control Board, Canada)
Approved By:
5j/94
D te
Inspection Summary
Inspection conducted February 28 through April 5, 1994 (Reports
No. 50-237/94003CDRS); No. 50-249/94003CDRSll
Areas Inspected:
An announced team inspection of engineering and technical
support and related management activities. The inspection was conducted
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utilizing portions* of inspection procedures 37700, 92701, 92702, and 92720 and
draft inspection procedure 37550 to ascertain whether engineering and
technical support was effectively accomplished and assessed by the licensee.
Results:
Based on the items inspected, overall performance in engineering and
technical support was considered acceptable. The level, quality, and
timeliness of engineering and technical support for the plant appeared to be
acceptable.
Most of the individuals contacted were knowledgeable and
motivated and displayed a strong sense of ownership in their areas of
responsibility, however, there were some-exceptions as noted in this report.
Significant improvements were noted in the Site Engineering and Construction
Organization, however, there were several findings where engineering
activities had not been thorough and the necessary attention to detail was
lacking. Little improvement was evident in the Systems Engineering
Organization.
The most significant weakness appeared to be in the control of temporary
alterations and lack of compliance to plant procedures.
The most significant
strength appeared to be the Site Engineering and Construction Organization
management's motivation and commitment to improvement.
Two violations, one with.two examples and one with three examples 9 were
identified. Violations included weaknesses in design control and a lack of
compliance to procedures.
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DETAILS
1.0
Pri~cipal Persons Contacted
Commonwealth Edison Company CCECo)
- * * * *
- *
H. Massin, Site Engineering Construction Manager
G. Spedl, Station Manager
S. Elderidge, Modification Coordinator
R. Jackson, System Engineering Team Leader
R. Robey, Site Quality Verification Director
J. Shields, Regulatory Assurance Supervisor
J. Smentek, Site Engineering Construction Engineer
D. Spencer, Lead Electrical - Plant Support
M. Strait, System Engineering Supervisor
J. Williams, Site Engineering Construction Supervisor
R. Wroblewski, NRC Coordinator
U. S. Nuclear Regulatory Commission
- *
R. Crlenjak, Acting Deputy Director DRS
M. Leach, Senior Resident Inspector
P. Hiland, Chief, Projects Section lB
C. Phillips, Resident Inspector
W. Shafer, Chief, Maintenance and Outage Section
A. Stone, Resident Inspector
- Denotes those present at the exit meeting on April 5, 1994.
Other persons were contacted as a matter of course during the
inspection.
2.0
Licensee Action on Previous Inspection Findings
A number of problems or concerns identified in past NRC inspections were
reviewed for appropriate corrective actions.
The items reviewed and the
inspectors' evaluations of the actions to address these issues are
discussed in this section. *
2.1
(Closed) Unresolved Item (237/249/91025-02)
Procedures were not
followed in providing fire watch coverage.
Licensee personnel indicated
that fire watch coverage was not required since the fire barriers
involved were non-rated barriers located in the same fire area.
Procedure DFPP 4175-01, "Fire Barrier Integrity and Maintenance," was
revised to clarify rated and non-rated fire barriers. This item is
closed.
2.2
(Clbsed) Inspection Follow-up Item (237/249/93008-01) -- Evaluation to
examine the possibility of conducting a temperature effectiveness test
on the LPCI/CCSW heat exchangers.
Plans had been made to conduct a
temperature effectiveness test on the LPCI/CCSW heat exchangers;
however, due to the difficulties involved, the tests might not be
conclusive.
The present method of performing preventive maintenance on
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these exchangers appeared to be sufficient to assure proper operation.
This item is closed.
2.3
{Closed) Inspection Follow-up Item (237/249/93008-03) -- Expanded
acceptance criteria, used in the testing of the emergency diesel
generator cooling water pump, did not meet ASME code requirements.
Revision 11 of procedure DOS 6600-08 was issued to eliminate acceptance
criteria for the diesel generator cooling water pump flows.
The
acceptance criteria was revised to be consistent with ASME code
requirements and was included in table 10 of the Dresden In-Service
Acceptance Criteria Manual.
This item is closed.
2.4
CCl~sed) Inspection Follow-Llp Item (237/93015-01) -- There was no method
or criteria for identifying excessive stem nut wear on motor operated
valves. Although there was still no method or criteria for measuring
excessive stem nut wear, discussions with licensee personnel indicated
- that maintenance personnel were aware of the stem nut wear problem and
the stem nut was visually inspected in place for signs of excessive wear
during normal MDV preventive maintenance activities.
In addition, a
search was underway for a reliable and economical method for measuring
stem nut wear including acceptance criteria.
2.5
{Closed) Inspection Followup Item (237/249/93020-09) -- Root cause
investigation and corrective actions for spurious group V primary
containment isolations due to flow spiking. This item is closed based
on the review associated with licensee event report (LER} 237/92-45
supplement 2.
2.6
{Open) Unresolved Item (237/249/93030-0lCDRS)) -- Acceptability of using
sampling inspection for quality control (QC) hold points.
Random
sampling was used to verify QC hold points for inspections required by
ANSI/ASME NQA-1, "Quality Assurance Program Requirements for Nuclear
Power Plants," 1989, and ANSI/ASME NQA-2, "Quality Assurance
Requirements for Nuclear Facility Applications," 1989.
On December 3,
1993, licensee personnel requested an interpretation from the American
Society of Mechanical Engineers (ASME} concerning the use of sampling
for required inspection activities.
No interpretation had yet been
provided at the time of this inspection. This item will remain open
pending receipt and* review of the interpretation provided by ASME.
2.7
{Open) Violation 237/249/93030-02{DRS) -- The procedure, which
controlled the use of measuring and test equipment (M&TE}, did not
provide appropriate qualitative or quantitative criteria for performing
evaluations of tested and inspected equipment when measuring and testing
equipment (M&TE} were determined to be lost or were found to be out of
calibration.
An action plan had been developed to provide necessary
improvements in the M&TE area.
Many of the actions, required by the
plan, had not been implemented.
At the time of the inspection,
Procedure DAP 11-22, "Control of Measuring and Test Equipment," had not
been revised and the review of instrument evaluations back to January,
1993, had not been completed. This violation will remain open pending
additional review when commitments have been completed.
2.8
{Closed) Violation (237/93030-03) -- Measures were not established to
assure that deficiencies and deviations identified by contract quality
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2.9
2.10
3.0
3.1
control inspectors on observation reports were corrected.
Licensee
personnel reviewed observation reports initiated in 1993 and initiated
problem identification forms (PIFs) for observation reports which had
not been resolved.
Licensee and contractor personnel began using PIFs
to document problems identified by contractors. The inspectors
interviewed contract QC inspectors and confirmed PIFs were being used in
lieu of observation reports. This violation is closed.
(Closed) Inspection Follow-up Item (237/93030-04) -- There was no
investigation to determine the cause of the miswiring of the limit
switch for the high pressure coolant injection (HPCI) containment
isolation valve, which resulted in a failure of the valve to open in May
of 1993.
Licensee personnel's investigation identified the causes as
failure to follow work instructions and inadequate emphasis on
implementation of change documents (such as the field change request
which implemented modification Ml2-2-92-001G).
As part of the
corrective action, licensee personnel provided training to Site
Engineering and Construction (SEC) personnel involved in the
modification process. This item is closed.
(Open) Unresolved Item (237/249/93034-06) -- A portion of the Unit 2
core spray leak detection instrument lines had not been tested. This
item was reviewed and the majority of the work was still pending.
This
item will remain open.
Licensee Action on Licensee Event Reports
The inspectors reviewed the action taken on a number of licensee event
reports (LERs) for appropriate corrective actions.
The LERs reviewed
and the inspectors' evaluations of the actions to address these issues
are discussed in this section.
(Closed) Licensee Event Report 237/87-010 -- This LER 9 dated February 2,
1987, reported that the embedment plate for support Mll50-D-62 on the
Unit 2 Core Spray system had pulled away from the ceiling 1/8
11 to 1/4
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During the review of records related to this LER 9 the inspectors noted
that calculations concluded that the damage was caused by water hammer.
The water hammer was not reported in LER 87-010 or by a separate LER.
Licensee personnel committed to update LER 87-010 to include
documentation of the water hammer, root cause evaluation, and corrective
actions.
Licensee personnel performed a walk down of the system and found no
other damage.
The damage to the support was repaired and an embedment
plate assessment program was completed at both the Dresden and Quad
Cities stations. The hardware changes made to correct the damage to the
pipe supports appeared to be adequate.
This item is closed.
3.2
(Closed) Licensee Event Report 237/91-012: This LER, dated October 3,
1990, reported significant corrosion on Unit 2 pipe support M-3212-05 at
the base plate and on the.exposed portion of the concrete expansion
anchors.
The cause was attributed to corrosion induced by standing
water in the HPCI steam tunnel.
The standing water was due to ground
water in-leakage. Licensee personnel resolved the problem by injecting
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hydrophilic.polymer resin into the concrete cracks where the in-leakage
was found.
This item is closed.
3.3
{Closed) Licensee Event Report 237/92-045-2 -- This LER supplement,
dated January 28, 1994, provided follow up information on an isolation
condenser group V isolation due to spurious flow spikes. The cause of
the flow spikes was determined to be process noise from operation of the
shut down cooling system.
To reduce the number of spurious group V
isolations, licensee personnel revised operating procedures to isolate
the system when not required by Technical Specifications.
Licensee
personnel planned to supplement the LER to correct information
concerning the corrective actions. The inspectors reviewed the
procedural changes and no concerns were identified. This item is
closed.
3.4
{Closed) Licensee Event Report 237/93-001: This LER, dated December 23,
1992, reported a pipe support removal to allow the installation of a new
support on the isolation condenser clean demineralized water fill system
without analyzing for this condition.
The inspectors reviewed the
corrective actions taken to resolve the problem and considered them to
be acceptable. This item is closed.
3:5
{Closed} Licensee Event Report 237/93-012:
This LER, dated May 18,
1992, reported that the Unit 2 emergency diesel generator breaker failed
to auto-close as required.
The LER indicated that the Bus 24-1 main
supply breaker linkage arm which, upon breaker operation, positions the
breakers cell mounted auxiliary switches, had been bent.
Upon opening
of the main bus supply breaker, the auxiliary switch did not change
position to indicate to the diesel generator breaker closing logic
cir~uit that the main supply breaker was open.
Thus the incoming diesel
generator breaker closing logic was blocked.
Corrective actions
included the replacement of the cell switches and linkage arms with a
new design mechanism similar to that used in the 4.16KV upgrade
modification. This item is closed.
3.6
{Open) Licensee Event Report 237/94-006:
This LER, dated February 5,
1994, reported that Unit 2 shutdown cooling pump motors 2A, 28 and 2C
had been replaced with motors which had different electrical
characteristics and*the protective relay settings had not been changed
or evaluated for the new motors.
Subsequent evaluation and analysis
resulted in resetting the relays to accommodate the replacement motors.
During a review of the documentation and analysis which documented the
revised relay settings, the inspectors noted that the consultant who
developed the new settings, expressed concern regarding the motor
acceleration current versus time characteristics.
An attachment to a
letter dated February 10, 1994, stated that the consultant could not
verify that the settings would allow acceptable motor starting. The
CECo Systems Protection Department concurred and strongly recommended
that the station conduct testing to determine the motor starting
characteristic curves at the earliest convenience.
When queried,
licensee personnel were unable to find evidence that testing had been
con.ducted.
This LER wi 11 remain open pending performance of the testing
and the NRC review of the test results.
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4.0
Inspection Objectives
The objectives of the inspection were to determine if engineering
activities supporting the Dresden Power Station were properly
coordinated and effectively controlled and implemented.
The inspectors
focused on the identification and resolution of technical issues and
problemst design changes and modifications, and internal assessments of
engineering. This was accomplished by observation of work activities,
interviews with selected personnel (including engineers and engineering
management), and reviews of records, procedures, and associated
documentation.
4.1
Performance Data and System Selection
The selection of systems and components for emphasis during this
in~pection was based on a review of data from licensee event reports,
latest SALP information, and discussions with cognizant NRC personnel.
The systems selected were the Reactor Containment, Standby Liquid
Control System and Standby Gas Treatment systems. Modifications and
records for specific electrical, mechanical, and instrumentation
components of these systems were selected for review.
Activities and
documentation involving other systems and components were selected and
reviewed during the inspection to supplement the selected systems.
Consideration was given to the systems and components considered most
safety significant.
4.1.1 Reactor Containment
The inspectors reviewed selected records and walked down the accessible
portions of the reactor building. The following observations were
noted:
4.1.1.1 Containment Isolation Valves Operability Assessments
The inspectors reviewed two operability assessments performed by Site
Engineering and Construction (SEC) personnel. These assessments, dated
March 8, 1994 and March 10, 1994, concerned the HPCI, reactor water
cleanup, and isolation condenser containment isolation valves.
The
assessments were performed in response to Electric Power and Research
Institute testing of motor operated valves (MOVs) which indicated that
higher actuator thrust might be required for certain types of MOVs.
Based on the assessment results, the Unit 3 HPCI containment isolation
valves were declared inoperable on March 3, 1994.
As a result, the
Unit 3 refueling outage, D3Rl3, was started early. This issue will be
followed through the LER reporting system (LER number 94-006).
The assessment concluded that the Unit 2 HPCI containment isolation
valves were operable because of sufficient margin provided by MOV
upgrades completed during a May 1993 outage.
The other valves evaluated
also had sufficient margin to be considered operable.
No concerns or
problems with the operability assessments were identified.
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4.1.1.2 Design of.the Containment Hardened Vent System
The inspectors reviewed modifications Ml2-2-90-029 and Ml2-3-90-029,
which required the addition of a hardened containment wetwell vent to
meet Generic Letter 89-16.
Installation of the modification was
completed February 11, 1993.
The following design inadequacies or
weaknesses were noted:
a.
Inoperability of Containment Vent and Purge System -- The hardened
containment vent was specifically required for conditions beyond
the original plant design/licensing bases which include loss of
offsite power and failure of,non-safety-related systems such as
the instrument air system.
Although the new vent valves added by
this modification were capable of being operated upon loss of
normal instrument air, the existing containment vent and purge
system valves, which are in the vent path, were designed to fail
closed upon loss of power or instrument air. Since the existing
valves could not be opened, the system would be inoperable for the
event for which the system was intended. These valves also could
not be operated manually because they had no manual operators and,
in case of an accident, they could be inaccessible due to high
radiation levels.
b.
Failed fuel events were not properly considered -- Failed fuel
events were not considered in the design of these modifications.
It was evident from statements in Generic Letter 89-16, as well as
other related documents, that failed fuel was intended to be
addressed.
c.
The effects of entrained water were not properly considered -- The
system would be required to handle significant masses of water and
the effects of this water were not adequately considered.
Some of
these effects were the weight of the water, the potential for
water hammer, and the reduction in venting capacity.
Examples of
where these effects weren't properly considered were Calculation
XCE065.0200.001, "Determination of Required Hardened Wetwell Vent
Flow Rate and Vent Pipe Size," Revision 0, which did not consider
the flow capacity reduction, and operating procedure DOP 1600-21,
"Draining Augmented Primary Containment Vent System," Revision 0,
which prohibited system draining for containment pressures greater
than 1.86 psig, making this procedure unusable for the targeted
accident.
d.
The strengthened vent system was incomplete -- The hardened vent
line exhausted into the non-hardened ventilation ductwork located
outside the turbine building which connected with the plant stack.
There was no evidence that the weight of the water, the dynamic
exhaust effects, and the potential for backup into the other
branches of this ductwork was considered. There was no evidence
that the stack would handle the water.
e.
Radiant Heating was Not Considered -- The purchase specification
for the hardened wetwell vent valves and associated hardware
identified 120° F as the maximum temperature for the valve
operators and associated equipment.
No consideration was given to
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radiant heating from the adjacent vent piping containing 310° F
steam.
Design of Backup Air Accumulators
Accumulator Sizing -- The backup air accumulators were installed
to provide air for operation of the valves installed during the
modifications. Only starting air pressure and pressure loss due
to valve stroking were used to determine the size of the backup
air accumulators. Other factors which should have been considered
were (1) minimum pressure to operate and hold the valves against
the maximum differential pressure and flow conditions, (2) system
leakage for the event duration, and (3) potential cooling during
the event.
Accumulator Testing -- Modification test procedure, M12-3-90-029~
did not require adequate testing of the leak tight integrity of
the valves' air operator systems. A minimum pressure to which the
system could decay and still be operable for the required number
of cycles was not established. The minimum pressure specified did
not account for pressure losses for the five operating cycles and
due to cooling. A starting pressure corresponding to the minimum
instrument air supply pressure and a test period correlated to the
accident duration were not established.
Licensee personnel contended that the design was consistent with the BWR
Owners Group (BWROG) recommended design criteria for this system and
that NRR had agreed with the BWROG design criteria. The inspector's
review of the NRC/BWROG correspondence revealed no statement which
concurred with the design criteria or limited the design requirements to
a long-term loss of decay heat removal event but which would not entail
significant fuel failure or other factors. This matter will be
forwarded to the Office of Nuclear Reactor Regulation for further
review.
4.1.1.3 Containment High Energy Line Break Vulnerability
The reactor building closed cooling water (RBCCW) system provided
cooling water to two heat loads inside the drywell, the drywell coolers
and the reactor recirculation pump seals.
MOVs were provided at both
the RBCCW supply and return containment penetrations, however, these
valves are not automatic.
The RBCCW piping inside containment is not
designed against a high energy line break event and no credit can be
taken for operators closing these valves until ten minutes into the
event. Therefore, in a loss of coolant accident, the primary
containment could be bypassed through the open containment isolation
valves and the RBCCW head tank vent line.
The MOVs, in the RBCCW supply and return lines, were non-automatic
containment isolation valves for the RBCCW System.
These valves, 2(3)-
M0-3706 and 3769-500, were not included in the Technical Specification
3/4.18 Primary Containment Isolation Valve List. These valves were
subject to 10 CFR 50, Appendix J, testing and were included in the
containment local leak rate testing program.
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In order to reduce the significance of this issue until final
resolution, licensee personnel have incorporated a requirement to close
these MOVs in case of a coolant accident in the abnormal operating
procedures.
The inclusion of this valve closing requirement in the
emergency operating procedures is under review.
This matter will be forwarded to the Office of Nuclear Reactor
Regulation for further review and generic implications.
4.1.2 Standby Liquid Control System *
During the review of records for the standby liquid control (SBLC)
system, the inspectors noted some design errors in modifications Ml2-2-
84-119 and Ml2-3-84-119.
These two modifications were installed in 1986
and 1987, to address an anticipated transient without scram (ATWS).
The original design pressure for the system was 1,275 psi. With two-
pump operation, as required by the modification, the new injection
pressure was calculated to be 1,330 psig. There were no indications
that the increase in pressure was recognized by the licensee and, as a
result, the design pressure of the piping and components was not
increased to accommodate two-pump operation.
During discussions on the matter, licensee personnel stated that the
piping was physically the same as the 1,500 psi design pressure piping
located elsewhere in the system and, therefore, the piping could be
expected to withstand the additional pressure without detrimental
effects. Based on this information, the direct safety significance of
the design verification oversight appeared to be low; however, the
discrepancies indicated a lack of thoroughness and verification in the
design process at the time of the modifications.
Additional errors noted included the following:
a. *
Inadequate Post-Modification Testing -- Post modification tests
required that the system operation be demonstrated with two pumps
discharging at 1,275 psig.
Post-modification testing did not
require that the system perform at the required design conditions
and, therefore~ the testing was not adequate.
b.
Technical Specification not Updated -- During the inspection, the
inspectors noted that Section 3/4.4 of the Technical Specification
had not been updated to require surveillance testing at the higher
pressure.
c.
Inadequate System Testing Procedures -- Test procedures for the
SBLC pumps and system had not been revised to require testing at
the higher pressure. These procedures, as noted during the
- inspection, were:
(1)
DOS 1100-01, "Standby Liquid Control System Pump Test,"
Revision 15.
(2)
DOS 1100-03, "Standby Liquid Control Injection Test,
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Revision 16.
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(3)
DOS 1100-04, "Quarterly Standby Liquid Control System Pump
Test for the Inservice Testing (IST) Program," Revision 10.
d.
Standby Liquid Control Design Basis Document Errors -- The
inspectors reviewed portions of the Standby Liquid Control Design
Basis Document, DBD-DR-139, Revision A, which was issued
September 22, 1993.
The system pressure errors described above
were found to be included in this document.
These problems indicated a lack of accuracy, thoroughness and
verification in the design process. The ability of the modified
system to perform as required had never been demonstrated.
The
inaccuracies in the DBD provide a flawed design basis for future
modifications, operability determinations, procedure changes,
etc., all of which could affect the safe operation of the plant.
This failure to provide adequate design control is an example of a
violation of Criterion III of 10 CFR 50, Appendix B
(237/249/94003-0l(DRS)).
During discussions near the end of the inspection, licensee
personnel indicated that steps had been initiated to correct the
design errors and impacted documents.
The SBLC system DBD had
been withdrawn from use and was to be thoroughly checked.
Steps
were in progress to ascertain the quality of the other issued
DBDs.
An example of one violation was identified in this area.
4.1.3 Standby Gas Treatment System
4.2
The inspectors reviewed selected records and walked down the accessible
portions of the standby gas treatment (SBGT) system.
In this area, the
inspectors reviewed an operability assessment for the SBGT system, dated
January 26, 1994. The evaluation documented a decision that the SBGT
system was operable even though the control room SBGT system temperature
indicators provided inaccurate readings. The control room indicators
were not used for operating procedures and the SBGT system surveillance
procedures were revised to use local temperature indicators instead.
The local temperature indicators provided more conservative data than
the control room indicators. Although this operability assessment
appeared to be acceptable, operating for an extended period in this
condition was not considered desirable, since the inability to use these
control room temperature indicators added to the normal operator
workload.
Observations of Plant Conditions
Early in the inspection, the inspectors performed walkdowns to determine
the material condition of the plant.
Indications of equipment problems,
housekeeping and other unusual conditions were noted.
Both units were
operating during this portion of the inspection. Plant conditions were
also observed during the review of modification and other engineering
support activities throughout the inspection.
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None of the problems noted appeared to have an immediate safety
significance or a significant effect on the operation of the plant.
Most equipment in need of repair had been previously identified by
licensee personnel. Overall, the facility appeared to be in better
material condition than during the previous engineering and technical
support inspection. The deficiencies noted, however, indicated that
more attention needed to be focused on less traveled and less accessible
portions of the facility.
The following adverse or unusual conditions were noted:
a.
HPCI System Pipe Supports -- The inspectors observed a significant
difference between Unit 2 and Unit 3 HPCI support and restraint
arrangement for the pump discharge and cooling water return to the
condensate storage tank line, at the pipe riser elbow.
The piping
configuration for both units were similar in this area.
For
Unit 2 the restraint was an anchor made from a dead weight support
and for Unit 3 the restraint was a sliding support.
On March 10, 1994, a PIF was written for the Unit 2 anchor as-
found condition.
The anchor was not analyzed in the original
piping analysis, and was not analyzed during the IEB 79-14
walkdown and evaluation program.
The operability analysis
performed on March 11, 1994, determined that the design stresses
were within the FSAR limits. The inspectors reviewed the records,
and noted that the rigid support was upgraded in 1970 by adding
bracing and a vertical column below the support.
During
construction, the interface between the pipe and the support
surface was inadvertently welded up; this in effect changed the
rigid support into an anchor.
A walkdown to determine IE Bulletin
79-14 discrepancies failed to identify this discrepancy.
Since the dead weight support in Unit 3 had not received an
upgrade similar to the one in Unit 2, the adequacy of the support
was in question.
Licensee personnel presented the Support
calculations, performed in 1983 appeared to be adequate.
This
matter is considered resolved.
b.
SBGT System Damper Operator -- Grease was noted on the electrical
connection for the limit switch housing on the operator for
ventilation damper MO 2/3-7505A.
The damper was the inlet
isolation damper for the "A" train of the SBGT system.
Because of
the location, the grease could have been coming from inside the
actuator limit switch housing.
Excessive grease in the limit
switch portion of the actuator housing could adversely affect
operation of the actuator. Licensee personnel agreed to remove
the limit switch housing cover during the next maintenance outage
for the SBGT system "A" train to determine the source of the
grease. Although the system engineer was aware of the grease, he
did not realize that grease might be inside the limit switch
housing and could adversely affect the actuator.
c.
RBCCW system -- The inspectors noted that the RBCCW system
included several valves that were missing nuts from packing
glands, pipe hangers disconnected or not supporting load, and
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d.
e.
several small pipes rubbing on other pipes or hard surfaces.
Although these problems were not individually significant,
collectively, they showed how vibrations resulting from the RBCCW
pump and line cavitations were affecting the system.
4KV Switchgear -- During a walkdown of some safety-related 4KV
switchgear areas, the inspectors noted that the majority of bolts
on the rear panels of safety-related switchgears 23-1 and 24-1
were missing or not secured: These panels cover the switchgear
bus bars and need to be securely closed to prevent any possible
personnel injury or bus grounding. Additionally, several breakers
had been removed from their respective cubicles and neither the
breakers or the cubicle openings were properly covered. Although
no requirement existed, covering the breakers and the openings
with the provided covers was considered to be a good maintenance
practice for prevention of personnel injury and dust and dirt
intrusion.
One breaker~ removed from the cubicle in the Unit 2 Turbine
Building 4KV Room, was found to be unrestrained. This was not in
accordance with Dresden Operating Procedure (DOP) 6500-04,
"Racking Out 4160 Volt Manually Operated Air Circuit Breaker,"
which required that *breakers removed from cubicles be restrained
to prevent rolling.
The failure to follow an approved station
procedure is an example of a violation of Criterion V of
10 CFR 50, Appendix B (237/94003-02A(DRS)).
Temporary Wooden Barriers -- During plant walkdowns, the
inspectors noted that temporary wooden structures had been erected
in front of safety-related motor control centers 28-1 and 39-1 to
serve as protective barriers during Unit 3 maintenance activities.
Discussions with licensee personnel indicated that the possible
impact of these barriers on plant operations had not been
evaluated.
When Unit 3 shut down for the outage, this ceased to
be a problem.
Licensee personnel were aware of the concern about
evaluations of unusual conditions during plant operations.
An example of one violation was identified in this area.
4.3
Engineering and Technical Support
Engineering and technical support at the Dresden Power Station was
provided by two separate organizations. Systems engineering support was
provided by the technical services organization and the site engineering
and construction (SEC) organization provided the support for design
changes and modifications.
The inspectors reviewed the engineering
support provided by both organizations.
4.3.1 Systems Engineering Support
Systems engineering support was provided by the plant technical staff.
- Systems engineers provided oversight for the assigned systems; these
engineers focused on daily operations-and maintenance activities of the
assigned systems or system components.
The engineers aided plant
operations and maintenance personnel in resolving technical issues and
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problems and* were involved in complex maintenance evolutions in the
assigned systems.
They also coordinated potential design changes with
other engineering organizations.
While conducting facility tours, the inspectors noted several material
condition problems with the RBCCW system and 4KV Switchgear. These
conditions were very visible and should have been identified by system
engineers, backup system engineers, or supervisors while performing
system walkdowns in accordance with System Engineering Memo SEM-01,
System Engineering System Walkdown Guidance.
A review of several system
engineering walkdown check sheets indicated that system engineers made
routine walkdowns but apparently failed to conduct thorough system
walkdowns in accordance with the intent of management guidance.
The experience and qualifications of system engineers was mixed.
The
inspectors noted several system engineers with less than two years
experience.
The apparent inexperience of some of the system engineers
appeared to be a problem in some areas.
Licensee personnel were aware
of this condition and, during the past year, had developed a formal
training program for systems engineers.
Most engineers appeared to have a reasonable understanding of the
assigned system functions and attributes; however, some engineers did
not always appear to be knowledgeable of the assigned systems and system
related problems. Adequate involvement of system engineers in plant
support activities was not always evident.
S9me system engineers did
not appear to be involved and some were less than aggressive in their
approach to involvement in activities relating to the assigned systems.
This was demonstrated by less than thorough system walkdowns and a lack
of *involvement of system engineers in the resolution of inspection
concerns. Repeated requests had to be made to get system engineering
involvement in NRC concerns during the inspection.
Based on the inspection results, the inspectors concluded that the
technical support for station activities, provided by systems
engineering, was adequate.
Even though systems engineers had been
relieved of direct responsibility and involvement in design changes,
very little improvement was noted in the System Engineering Organization
-since the E/TS inspection conducted a year ago.
4.3.2 Site Engineering and Construction
The site engineering and construction (SEC) organization had the primary
responsibility for coordination, evaluation, development, and
installation of design changes and modifications. This organization was
divided into four groups which included engineers with mechanical,
electrical and other engineerfng specialties. The primary purpose of
SEC was to develop and coordinate plant modifications, including design,
safety reviews, installation, and post modification testing in the
respective discipline.
Each modification was assigned to an engineer
actively involved in all phases of the modification. The engineers
completed walkdowns, as necessary, to ensure proper design
implementation and resolution of installation problems.
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Communications and coordination between site engineering and other plant
organizations such as systems engineers, plant management, operations,
maintenance, construction, and other plant personnel was effective.
Based on the inspection results, the inspectors concluded that, in most
cases, the SEC engineers were experienced and qualified. A substantial
improvement was evident. Most engineers appeared knowledgeable of the
assigned areas and appeared well motivated in their areas of
responsibility. The level, quality, and timeliness of engineering and
support in this area appeared to be good with a few exceptions. A
discussion of the exceptions follows.
4.3.2.1 Review of Modification Packages and Records
The inspectors reviewed selected portions of both open and closed
modification packages and supporting records, with emphasis on the
selected systems.
The records were reviewed to verify the packages were
complete and accurate, the modifications were adequately controlled, and
regulatory requirements were met.
The review included verification that
the description of the modification, the 10 CFR 50.59 safety screening
or evaluation, installation instructions, documentation of work
performed, post-modification testing requirements and test records were
adequate.
In some cases, other supporting records associated with the
modifications, such* as calculations and drawings, were selected and
reviewed to verify the adequacy and accuracy of the engineering process.
The 26 modification packages reviewed were:
Ml2-0-91-019F
Ml2-2-91-020
Ml2-2-91-022
Ml2-3-89-004
Ml2-3-91-022
Pl2-2-90-718
Pl2-3-91-731
Ml2-2-84-119
Ml2-2-90-028
Ml2-2-93-004
Ml2-3-90-013A
Ml2-3-93-004
Pl2-2-91-660
Pl2-3-92-612.
Ml2-2-88-60
Ml2-2-90-029
Ml2-3-84-119
Ml2-3-91-020
Pl2-2-90-710
Pl2-3-91-729
Problems or concerns noted during the review were:
Ml2-2-89-004
Ml2-2-91-021
Ml2-3-88-60
Ml2-3-91-021
Pl2-2-90-713
Pl2-3-91-730
a.
Ml2-2-90-029 ~- This modification installed the hardened wetwell
vent required by Generic Letter 89-16.
Problems with this
modification are discussed in Section 4.1.1.2 of this report.
b.
Ml2-2{3l-84-119 -- These modifications installed changes to the
SBLC system to comply with the ATWS rule.
Problems with this
modification are discussed in Section 4.1.2 of this report.
c.
Ml2-3-90-13A -- This partial modification (including Addendum 1
and 2) was required to add an alternate 125V DC battery system,
including a battery charger, a battery and connecting cables, to
the Unit 3 safety-related DC control system. This would allow the
normal battery system to be removed from service for required
testing without having to enter into a duel unit LCO. This partial
modification was completed in January of 1993.
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The inspectors noted that control room drawing 12E-2322B,
"Overall key Diagram, 125V DC Distribution Centers, Dresden
Nuclear Power Station Units 2 & 3," Revision C, dated July 3,
1991, had not been marked or revised to show the Unit 3 alternate
battery, battery charger or cabling additions, however, the
diagram did show the similar additions which had been made for the
Unit 2 modification.
Procedure DAP 02-09, "Control of Critical Drawings," required that
control room drawings be revised or updated to reflect the correct
plant configuration. The failure to implement the requirements of
this procedure and update the control room drawing with this
design change is considered an example of a violation of
Criterion V of 10 CFR 50, Appendix B (249/94003-02B(DRS)).
- Most of the modification packages and supporting records appeared to be
adequate.
With the exception of the noted deficiencies, records
indicated that modifications were adequately controlled and were
consistent with regulatory requirements.
The inspectors concluded that
th~ modification process was effective.
An example of one violation was identified in this area.
4.3.2.2 Review of Exempt Change Program
An Exempt Change (EC) Program had recently been developed to expedite
the review and approval of modifications of minor significance and with
low potential to significantly reduce the margin of nuclear safety.
This process replaced the former minor change process which was no
longer used.
These minor modifications were called "Exempt Changes" and
were process modifications which were exempt from the specific
requirements of the modification and minor plant change processes.
The inspectors concluded that the EC process provided a viable and
effective method to control minor modifications of low significance.
The records reviewed indicated that exempt changes were adequately
controlled, were consistent with regulatory requirements and the process
was effective.
4.3.2.3 Temporary Alterations
The inspectors reviewed the methods used to control temporary
alterations (TAs).
The methods were described in procedure DAP 07-04,
"Control of Temporary System Alterations," Revision 17.
The procedure
appeared to be inadequate in some areas. For example, a one time
justification was required for TAs to be installed more than 90 days.
Periodic review and justification for continued installation was not
required.
The Dresden Temporary Alteration Report, dated March 31, 1994, was
reviewed.
The report listed 48 open TAs, which was more than twice the
recently established goal of less than 20 open TAs.
The TA procedure
defined a TA to be an alteration expected to be installed for less than
six months.
Thirty of the TAs listed in the report had been open
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greater than six months and 10 had been open longer than two years.
This appeared to be a misapplication of the TA procedure.
Li c.ensee personnel stated that some recent changes had been made to
improve control and reduce the number of TAs.
A report of open TAs was
issued to management and the individuals assigned open TAs monthly.
Although some steps, such as the establishment of goals to reduce open
TAs, have been taken, management emphasis and action is needed to ensure
that appropriate action is taken and that thorough and adequate control
is provided for TAs.
Significant systems engineering involvement
appeared to be needed to eliminate and prevent the installation of
unneeded TAs.
Based on the review of the TA process and selected TA packages, the
inspectors considered the methods used to control TAs to be weak.
Problems were noted with five of the seven TA packages reviewed and the
number of TAs had increased approximately twenty percent in the last
year. Several problems involving both safety and non-safety-related
hardware were noted in this area. A discussion of these problems
follow.
4.3.2.3.1 Review of Temporary Alteration Records
The inspectors reviewed seven TA packages to verify proper control.
Problems or concerns were noted with five of the seven TAs.
The
packages reviewed and the results follow:
a.
TA II-33-93 -- This TA allowed the injection of "Furmanite" to
repair a leak in the valve packing area of valve 2-220-l02 in the
Unit 2 reactor recirculation system.
Installation of the TA was
completed May 27, 1993.
A hole was drilled into the valve yoke and sealant was injected
into the packing area to eliminate or reduce the leak.
The
engineering evaluation, performed at the time of installation,
failed to consider potential over pressurization of the valve due
to the sealant injection process.
Licensee personnel estimated
that the worst case injection pressure applied to the valve could
have been as high as 4700 psig which was considerably higher than
the valve's rated pressure of 3600 psig.
NRR is currently
reviewing control of the Furmanite process throughout the
industry.
The inspectors also noted that the valve affected by the TA formed
part of the reactor coolant pressure boundary, which was addressed
by Section 3.6 of the Technical Specifications. The screening
evaluation, included in the package, incorrectly concluded that no
safety evaluation was required.
During this inspection, an operability assessment for the valve
was performed and documented.
In addition, a safety evaluation as
required by 10 CFR 50.59 was performed.
The inspectors did not
identify any concerns regarding the operability evaluation and the
safety evaluation. Prior to this inspection, SEC personnel
recognized that oversight weaknesses existed with the sealant
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b.
injection process as early as May, 1993.
However, formal tracking
of plans to develop a controlling document was not initiated until
February, 1994.
The emphasis for such tracking was largely due to
problems experienced with TA II-1-94 (feedwater pump suction valve
sealant injection repair); Information Notice (IN) 93-90,
"Unisolatable Reactor Coolant System Leak following Repeated
Applications of Leak Sealant;" and an industry notification
concerning sealant injections.
TA II-34-93 -- This TA disabled the Reactor Feed Pump (RFP) motor
cooling fan intake and exhaust damper controls to keep the dampers
in the fully opened position.
Installation of the TA was
completed June 11, 1993.
The TA was installed to ensure adequate cooling of the RFP motor
during the summer, since there had been problems with the
temperature control system.
The motor was cooled by continued
circulation of outside air through the ventilation ductwork with
all dampers fully open. This TA was left installed through the
winter with no evaluation of the possible adverse effect of over
cooling the motor.
With the dampers fully open, extremely cold
air from outside could be blown into the RFP motor by the
continuously running cooling fans.
During the inspection, the
systems engineer reviewed the computer point history data for the
RFP stator winding and noted that the lowest temperature was above
ambient.
The warm air that prevented the over cooling was
determined to be coming from the full open recirculation damper,
In addition, there was a lack of documentation of the problems
that required the TA.
Records only indicated that the exhaust
damper was broken.
Discussions with the responsible systems
engineer indicated that none of the dampers in the RFP motor
cooling system, including supply air damper, exhaust air damper,
and recirculating damper were found in their expected positions,
Some internal linkage slippage had also been identified. However,
there were no indications that action had been taken to correct
these problems to restore the temperature control system to proper
operations.
The control of this TA was inadequate. The system was allowed to
operate during the winter in an un-evaluated condition and the
corrective action to restore the temperature control system to
acceptable operations was not timely. This matter was discussed
with licensee personnel.
c.
TA II-60-93 -- This TA allowed the installation of inlet and
outlet pressure gauges on a refrigeration control unit heat
exchanger for control room heating, ventilation, and air
conditioning equipment.
Installation of the TA was completed in
December, 1993.
No problems or concerns were identified with this
TA.
d.
TA II-1-94 -- This TA allowed the installation of a "Furmanite"
clamp on the 2A RFP suction valve bonnet to body flange to stop or
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reduce*water leakage to an acceptable level. Installation of the
TA was completed January 11, 1994.
After the "Furmanite" clamp installation and sealant injection,
water leakage returned to the previous leakage rate in less than
one day.
The failure of the TA appeared to be improper control of
the "Furmanite" process.
The curing temperature for the sealant
compound not being specified in the work procedure and was not
monitored during "Furmanite"-injection.
Engineering Department
Technical Information Document TID-MS-06, "Injection Leak Seal~nt
Application General Use," December 30, 1991, did not require
monitoring of curing temperature during injection.
The work package required that a responsible engineer from SEC be
present when sealant compound was injected into the "Furmanite"
clamp.
This item was assigned to the mechanical maintenance
department and SEC was not involved in the work.
These concerns
were discussed with cognizant licensee personnel.
e.
TA III-21-92 -- Eight thermocouples, two pressure transducers, two
flow transducers, and one axial shaft displacement probe were
installed, under this TA, to monitor system parameters and to
assist in the determination of causes for RFP seal failures.
Installation of the TA was completed June 29, 1992.
f.
g.
In reviewing the package, the inspectors noted that there were no
design documents to identify the location. of the instruments, the
hardware to be used, the hardware accuracy and the functional test
requirements.
In 1988, the RFP supplier recommended changing to another type
seal. The recommended seals were purchased and installed in all
Unit 2 RFPs in late 1992.
No Unit 2 RFP seal failures had been
reported since. The inspectors concluded that the TA was not
adequately engineered and that the change appeared to have little
or no actual value since the change in the type of seal had
apparently solved the problem.
These concerns were discussed with licensee personnel.
TA Ill-22-92 -- This TA was implemented to bypass a switchboard
mounted fuse holder which included a solid copper link rather than
an actual fuse.
Installation of the TA was completed July 2,
1992.
No problems or concerns were identified with this TA.
TA 111-40-92 -- This TA involved the existing 7-second time delay
feature of the degraded grid voltage protection scheme for the
Unit 3 safety-related 4.16KV bus 33-1.
Installation of the TA was
completed October 30, 1992.
On March 10, 1994, the inspectors reviewed the control room copy
of the drawing 12-3345, Sheet 2, "Schematic Control Diagram, 4160V
Bus 33-1, 4KV Swgr. Bus 40 Feed Bkr., Unit 3," Revision AF, dated
March 9, 1993, titled and noted that the markings on the drawing
did not agree with the TA.
The markings indicated that the relay
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time delay was 2-seconds rather than the required 7-seconds. The
replaced relay was still indicated as an instantaneous relay,
rather than the installed time delay relay, as called for in the
TA documentation.
Procedure OAP 02-09, "Control of Critical Drawings," required that
control room drawings be revised or updated to reflect the correct
plant configuration.
The failure to implement the requirements of
this procedure and correctly- update the control room drawing with
the plant configuration for this temporary alteration is
considered an example of a violation of Criterion V of 10 CFR 50, Appendix B (249/94003-02C(DRS)).
Examples of two violations were identified in this area.
4.3.2.4 Review of Safety Evaluations and Screenings
The inspectors reviewed the methods used to perform 10 CFR 50.59 safety
screenings and evaluations. Records of the screenings and evaluations
were reviewed for the selected modification, exempt change and temporary
alteration (TA) packages to verify completeness, accuracy, and
compliance with regulatory requirements.
Procedure OAP 10-02, "10CFR50.59 Review Screenings and Safety
Evaluations," Revision 8, was reviewed and found to be well written and
concise. Several minor weaknesses were noted and discussed with
licensee personnel for possible procedural improvements.
Licensee
personnel acknowledged these weaknesses and indicated that the procedure
would be revised.
During the review of modifications M12-2(3)-93-004, the inspectors noted
that an unreviewed safety question was identified during the original
10 CFR 50.59 safety evaluation performed for the modifications.
Due to
discussions with the Office of Nuclear Reactor Regulation regarding the
issue, the modification was subsequently redesigned to eliminate the
unreviewed safety question.
As a result of the identification of this
problem, Information Notice 93-89, "Potential Problems with BWR Level
Instrumentation Backfill Modifications," was issued. The inspectors
considered the identification and resolution of this issue to be a
positive application of the 10 CFR 50.59 safety evaluation process.
Safety evaluations or screenings were usually performed and were
acceptable.
The modification and TA packages reviewed contained the
required 10 CFR 50.59 safety screenings or evaluations and they appeared
to be well documented.
Some of the packages contained additional
supporting information.
Procedure OAP 10-02, if properly implemented,
provided sufficient controls to ensure that proper 10 CFR 50.59
screenings and safety evaluations were performed and documented as
required.
Based on the review of records and subsequent discussions
with licensee personnel, the inspectors concluded that the safety
screenings and evaluations were acceptable.
4.3.2.5 Review of Calculations
In order to complete the assessment of the design change and
modification process, the inspectors reviewed portions of selected
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calculations that were performed or revised to support the selected
modifications. Calculations were reviewed for completeness, accuracy,
validity of assumptions, and conservatism with emphasis on how well the
calculations supported the respective modification.
Some of the
calculations were performed by licensee personnel while others were
performed by contractors.
Based on the review of calculations, the inspectors concluded that,
overall, calculations were acceptable. Several calculation errors were
noted. Although most of the indivi~ual problems in this area were not
considered to have a significant effect on equipment function,
improvement was needed in this area. This matter was discussed with
licensee personnel.
The following concerns were noted during the review of calculations:
a.
Calculation 8982-19-19-2, "Calculation for Contactor/Interposing
Relay Coil Voltage at Pickup,"
Revision 1, dated December 22,
1992 -- Revision 0 of this calculation identified the marginally
acceptable conditions for the contactor coils associated with the
modifications Pl2-3-92-611, 612, 613 and 614.
However, the
results and conclusions of this calculation, including.Revision 1,
indic~ted that the minimum pickup voltage acceptance criteria was
not met by six circuits. These control circuits were identified
as those for the following motor loads:
HPCI auxiliary coolant pump,
HPCI pump area cooling unit,
reactor protection system MG set 3B,
reactor building cooler recirc pump,
motor operated valve 202-4A and
motor operated valve 202-48.
Licensee personnel indicated that these six circuits had been
analyzed and the conditions had been resolved or justified.
Documentation could not be located to support this response.
Licensee personnel advised that they would continue to search for
the documentation and, if the records could not be found the
conditions would be reanalyzed and new documentation prepared.
The inspectors considered this to be an inspection follow up item
pending NRC review of the documentation and resolutions
(249/94003-03(DRS)).
b.
Calculation XCE065.0200.001, "Determination of Required Hardened
Wetwell Vent Flow Rate and Vent Pipe Size," Revision 0, dated
July 19, 1991 -- Details of this calculation were discussed in
Section 4.1.1.2 of this report.
c.
Piping stress analysis for the LPCI p1p1ng system -- During a
visit to a CECo design contractor on March 16, 1994, the
inspectors noted that only one uniformly hot temperature was used
in the original piping analysis for the HPCI system.
The
inspectors counted five different temperature combinations.
Since, in some cases, thermal loads were dominating loads,
licensee personnel agreed to re-run the piping stress analysis for
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the LPCI piping system in a simplified manner.
The review focus
was placed on the heat exchanger 28-1503 outlet nozzle.
This heat
exchanger had the largest design loading imposed on the over-
stressed structural wide flange in Unit 2 southwest corner room.
The piping stress analysis showed significantly higher loadings in
some directions. This raised a question on the validity of some
of the earlier piping stress analysis.
Licensee personnel also agreed to re-run the seismic and dead
weight analyses and to perform a technical audit on the previous
piping stress analysis. This matter is unresolved pending review
of the stress analysis and audit {237/249/94003-04}.
4.4
Errors in the Updated Final Safety Analysis Report
During the inspection the inspectors noted several errors in the
recently rebaselined Updated Final Safety Analysis Report {UFSAR}.
These errors were:
a.
b.
On page 2.4-2, the statement is made that the Probable Maximum
Flood {PMF} level is 528'- 0".
Table 2.4-1 states that the
maximum flood is 508'-0".
Licensee personnel determined that the
correct PMF level was 528'- O", which is higher than the plant
ground elevation of 517' - 0".
The inspectors reviewed procedure
DOA 0010-04, "Floods," and noted that the procedure addressed this
type flood.
Several questions were raised and licensee personnel
issued a PIF to ensure that the issue was adequately addressed.
On page 6.2-4, the description of the primary containment airlock
was not correct.
c.
On page 6.2-17, the pressure in the suppression chamber was
described as 29 psia from an initial pressure of 0.5 psia. These
terms should have been psig.
d.
Table 6.5-2 of the UFSAR used incorrect units to reflect pressure
drops in standby gas treatment system. Specifically, "ft H20"
rather than "in H20" was used.
The multiple errors in the UPSAR indicated that the checking and review
of changes was inadequate to assure that the document was correct.
Licensee personnel indicated that the noted errors would be corrected.
5.0
Self-assessment of Engineering Activities
Self-assessment of engineering activities at the Dresden Station
consisted of audits and a special assessment of some engineering
activities.
In addition, some assessment of engineering activities was
accomplished by cause investigation and correction when problems
occurred. Overall, the various assessments covered the spectrum of
engineering support activities.
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5.1.
Sit~ Quality Verification Audits
5.2
The inspectors reviewed recent Site Quality Verification {SQV) audit and
special assessment records and interviewed personnel to determine the
effectiveness of the self-assessment of engineering activities. Audits
of the engineering group were normally conducted yearly with additional
audits of supplemental engineering activities conducted as needed.
Records of three SQV audits of engineering or engineering related
activities were reviewed and found to be adequate.
The SQV audit records indicated that the scope of the audits performed
was adequate to cover engineering activities. Findings and
recommendations noted appeared to be appropriate. The audits were not
always effective in finding engineering weaknesses.
For example, the
problem with the misuse of temporary alterations, noted during the
inspection, was not identified during these audits.
Corrective Actions Records {CARs) were issued for audit findings and
were incorporated into the NTS program.
CARs were also tracked by a
redundant SQV tracking system.
During one of the audits, SQV identified
problems in documenting TAs on control room drawings; however, actions
taken to correct the problem were not thorough.
As part of the response
to .CAR 12-9.3-034, a review of all open TAs was performed to ensure that
control room drawings properly reflected the TAs.
The inspectors
identified a TA which was not properly reflected on the applicable
control room drawings. This issue is discussed in Section 4.3.2.3.1 g.
of this report.
The inspectors considered the audits to be adequate.
Identification of
engineering weaknesses and follow up to ensure effective action was
taken on findings did not always happen.
No other concerns were
identified in this area.
Special Assessments of Engineering
Corporate SQV was primarily responsible for special assessments of
engineering.
No overall assessments of engineering had been performed
by this group in the last two years.
In response to continued problems associated with the maintenance of
drawings, however, SEC management used an outside consultant, Failure
Prevention, Incorporated, to study the problem.
The consultants'
report, "Organizational & Programmatic Assessment of the Critical
Drawing/Design Change Interface at the Dresden Nuclear Station," dated
December 1993, made several recommendations and provided useful insight.
As ~ result of the study, the changeover from manual to electronic
storage of critical drawings was accelerated, and organizational changes
were made to ensure qualified personnel updated critical drawings.
The
inspectors considered SEC management's use of an outside consultant to
study process and organizational problems a positive imitative.
5.3
Trending and Corrective Action
The inspectors reviewed the methods used by engineering to trend
equipment problems, investigate problems for cause, and provide adequate
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corrective action to correct both the identified problem and the cause.
Significant problems or failures were documented on PIFs, which were
used as a mechanism for investigation to determine root causes and
initiate actions to prevent recurrence. Trending and corrective action
are discussed separately in the following sections.
5.3.l Trending
- The inspectors reviewed the methods used to track problems, detect
repetitive equipment failures and trend hardware and other quality
related problems. A tracking system had been developed to track~ sort
and allow oversight of equipment failures and other potential problems.
The tracking system used a matrix to collect and sort information into
functional groups. Because of past problems with inadequate trending,
an oversight of this system was provided by the root cause committee.
The systems engineers were responsible for monitoring failure
information to detect repetitive hardware failures and problem trends in
the assigned systems or system related components.
A significant
problem had recently occurred in this area. Repetitive failures of the
reactor coolant level instrumentation had not been detected and
corrective action had not been taken, even though many failures had been
documented.
Because of this instrumentation issue, licensee management
had provided additional emphasis on trending of significant hardware
failures, however, it was too early to evaluate the results of this
action.
Another trending method used was the Component Failure Analysis Report,
which utilized information from the nuclear plant reliability data
system.
This system allowed a review of industry failure and trending
information on selected plant components.
Discussions with licensee
personnel indicated that, if failure rates were above the industry
average for the specified components, the issues were referred to the
appropriate system engineers for investigation and possible action.
The inspectors concluded that, although an acceptable trending program
appeared to be in place, additional management attention was needed to
ensure adequate implementation.
Some actions had been taken in this
area, however, the results could not be determined at this time.
5.3.2 Corrective Action
The inspectors reviewed the methods used for root cause investigation
and corrective action for hardware and other quality related problems.
Significant problems or failures, which required a review for cause of
failure, were documented on PIFs to track the problems for cause
investigations and resolutions. Systems engineers were normally
assigned follow up action for PIFs written on their assigned systems.
In order to improve the correction system, the threshold level for
writing PIFs had been reduced.
In addition, a root cause committee had
been developed. This committee met each workday to discuss items
requiring root cause investigation and possible corrective action. The
inspectors attended several of these daily meetings and concluded that
the use of the root cause committee was an effective method for
implementing the root cause program.
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Based on the review of the corrective action program, the review of
selected PIFs, attendance at several root cause committee meetings and
discussions with licensee personnel, the inspectors concluded that
actions taken to improve root cause investigations and corrective
actions had been effective and that the corrective action program was
acceptable.
In most cases, PIFs were written, properly processed,
evaluated for cause and the actions taken were appropriate and timely.
Improvements in the corrective action program were evident.
5.3.2.1 Nuclear Tracking System
The Nuclear Tracking System (NTS) was the method used for tracking
commitments, discrepancies, and material deficiencies. The system
database was managed by the Regulatory Assurance Group and each item was
assigned to a cognizant supervisor and individual. The system appeared
to be dynamic in nature with growing acceptance and usage.
The inspectors noted that the number of items receiving extensions and
the new items written exceeded the number of items closed for both
engineering groups for the past four months.
This trend had resulted in
an increasing backlog of open items assigned to the engineering staff.
Significant attention had been placed on the closure of items to ensure
that overdue items were promptly addressed and, as a result, the daily
NTS reports had very few items that were listed as overdue.
At the time
of the inspection, the increasing backlog did not appear to be a
problem, however, unless the trend is reversed, future difficulties will
be encountered.
Licensee personnel stated that extensions to scheduled
du~ dates now require approval of the responsible supervisor.
During discussions with licensee personnel, several individuals
commented that all open items had the same importance and the priority
was driven by the scheduled closure date, rather than safety or
operational significance. This was discussed with engineering
management who agreed that there was no formal prioritization of items
once the items were placed in the system.
Licensee personnel stated
that it was the responsibility of the supervisors to manage individual
workloads and, through that function, set priorities of assigned items.
A review of many open items found no evidence of significant items being
ignored or delayed due to work on less significant items.
5.3.2.2 Review and Evaluation of NRC and Industry Information
The inspectors evaluated the effectiveness of the methods used for
review and evaluation of NRC and industry information. This review
included the methods used to assure that vendor, industry, and NRC
generic information was controlled, distributed, and evaluated and that
corrective actions were taken as appropriate.
The Regulatory Assurance Department had the overall responsibility for
coordination of review and evaluation of this information.
Upon the
receipt of a notice or other information an initial screening for
applicability was performed.
Distribution to the responsible organization for impact evaluation and
determination of possible required action was coordinated with corporate
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6.0
engineering.. Assigned departments were required to provide a response
to Regulatory Assurance, noting any plant impact, with recommendations
for action if needed.
All of the applicable NRC and industry
information was tracked by Regulatory Assurance until the issues were
closed. Regulatory Assurance was also responsible for assembly of the
response package and preparation of the cover letter if a response was
required.
In order to determine the effectiveness of this system, the inspectors
selected the methods for handling supplier service information letters
(Slls} and NRC information notices (IN) for review.
These reviews are
discussed below:
a.
Service Information Letters -- The inspectors reviewed the methods
used for the dissemination and response to vendor SILs.
Several
SILs were reviewed and were found to be adequately tracked and
addressed by the technical staff. The individual responsible for
the SILs was knowledge of the current status of the SILs selected
and readily retrieved documentation for review.
b.
Information Notices -- Problems had been previously identified
with the program for controlling information notices. A review of
the program indicated that these problems still existed, however,
because the corrective actions for these issues were still
pending, no further assessment in this area was completed.
The licensee's lessons learned program, which provided interface and
communication on problems at other CECo plants, appeared to be working
effectively.
For example, the inspectors noted that Dresden systems
engineering was aware of and was tracking an incident that happened at
Quad Cities where a reactor recirculation pump inadvertently went to
fast speed while the unit was shutdown causing severe vibration and
possible damage.
Although the evaluation was ongoing, the systems
engineer appeared knowledgeable of the problem, actions taken and the
status.
Unresolved Items
Unresolved items are* matters* about which more information is required in
order to ascertain whether they are acceptable items, violations or
deviations.
An unresolved item noted during the inspection is discussed
in Section 4.3.2.5 c. of this report.
7.0
Inspection Follow-up Items
Inspection follow up items are matters which have been discussed with
licensee personnel, which will be reviewed further by the inspector, and
which involve some action on the part of the NRC or the licensee or
both.
An inspection follow up item, noted during the inspection, is
discussed in Section 4.3.2.5 a. of this report.
8.0
Exit Meeting
The inspectors met at the Dresden Nuclear Power Station with licensee
representatives {denoted in Section 1) on April 5, 1994, to summarize
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the purposer scope, and findings of the inspection. The inspectors
discussed the likely informational content of the inspection report with
regard to documents or processes reviewed by the inspectors during the
inspection, noting that three documents were identified as proprietary
during the inspection. Details of these documents are not discussed in
this report.
Licensee personnel were asked to identify any proprietary
information or material discussed during the exit meeting.
Licensee
personnel did not identify any information or material as proprietary.
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