ML17187B032
| ML17187B032 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 06/05/1997 |
| From: | Caniano R, Hiland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17187B030 | List: |
| References | |
| 50-237-97-07, 50-237-97-7, 50-249-97-07, 50-249-97-7, NUDOCS 9706270328 | |
| Download: ML17187B032 (52) | |
See also: IR 05000237/1997007
Text
U.S. NUCLEAR REGULA TORY COMMISSION
Docket Nos:
License Nos:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Submitted By:
Approved By:
9706270328 970613
ADOCK 05000237
G
REGION Ill
50-237; 50-249
50-237197007; 50-249/97007
Commonwealth Edison Company
Dresden Nuclear Station Units 2 and 3
Opus West Ill
1400 Opus Place - Suite 300
Downers Grove, IL 60515
April 14 through May 12, 1997
M. Farber, Reactor Inspector, Riii
B. Bartlett, Senior Resident Inspector, Riii
K. Riemer, Senior Resident Inspector, Riii
R. Paul, Senior Health Physics Inspector, Riii
C. Johnson, Reactor Inspector, RIV
F. Gee, Reactor Inspector, NRR
C. Settles, Inspector, Illinois Department of Nuclear
/3'1 /~ C/f/q7
P. L. Hiland, Chief, Fuel Cycles Branch,
Team Leader, Division of Nuclear Material Safety, Riii
a~c:~~~ 7!"/s-/7? .
J
aniano, Acting Director,
.
Manager, Division of Nuclear Material Safety, Riii
EXECUTIVE SUMMARY
Dresden Nuclear Station Units 2 and 3
NRC Inspection Report 50-237197007; 50-249/97007
This special safety maintenance team inspection included aspects of licensee maintenance,
engineering, and plant support. The report covered a 2-week onsite period of inspection
by the full team, and some onsite followup inspections conducted by individual team
members up to the date of the exit meeting held on May 12, 1997.
Maintenance Program
Work Control
The outage control center (OCC) functioned adequately and was providing the services
expected from it. Personnel staffing the OCC understood their positions and objectives,
and were generally supporting the outage adequately. With one unit in a refuel outage and
a second unit in a forced outage, coordination problems between the Unit 2 and Unit 3
outage organizations were initially observed early in the inspection; however, corrective
actions by the licensee significantly reduced the coordination problems over the 2-week
onsite inspection period.
The work execution center (WEC), located just outside the main control room, was
functioning effectively in reviewing and approving work packages and meeting the
objective of reducing control room operator distractions. However; uncontrolled
documents (desk top instructions) were being used in the WEC and elsewhere to enhance
existing approved procedures. The team considered the licensee's approach to resolution
of this issue acceptable.
The performance of work analysts was adequate, and work packages reviewed were
generally of good quality. The work package rejection rate, while not precisely fixed, was
not excessive. However, the work analysts were called upon to perform tasks which
would normally be considered engineering. Examples included parts evaluation and system
interaction analysis.
The original Unit 2 forced outage schedule was prepared to address three major problems:
the switch block cracks in Merlin-Garin 4kV breakers, leaking "X-area" coolers, and a
condenser tube leak. Each of these activities exhibited elements of inadequate planning or
coordination problems.
The licensee's existing and future scheduling systems appeared to be well thought out and
structured. With Unit 2 in a forced outage and the new program in the early stages of
implementation, an historical review was not conducted and no assessment was made
with regard to the effectiveness of either the 12-week or 5-week programs (rolling
schedules).
2
,J
.. ,
Two violations, with two examples each, were identified regarding the failure to follow
station administrative and surveillance test procedures. In the first example (M3.1 ),
station administrative procedures were not followed to obtain a controlled key, and in the
second example (M3.2), the station's approved method for independent verification was
not translated into the implementing instructions. In addition, the training of contract
Instrument Maintenance Department (IMO) technicians regarding the requirements of
independent verification was not consistent with other maintenance departments.
The third and fourth examples (M4.1) of a violation in this area involved failure to follow
test instructions. In one example, a power supply was left energized following testing
contrary to procedural direction, and the other example involved using a wrong procedure
.revision to perform testing .
Mechanical Maintenance Performance
Mechanical maintenance activities were generally well performed. However, a violation
with three examples of failure to follow station administrative requirements to assure
proper foreign material exclusion were identified (M4.2). A separate violation (M4.2) with
two examples was identified for failure to follow specific mechanical maintenance work
instructions. The first example was a failure to monitor weld interpass temperature, and
the second example involved performance of work without a sufficient work package at
the job site. In addition, some poor work practices were identified with regard to minimum
protective clothing requirements and unapproved rigging of components to piping systems.
Electrical Maintenance Performance
In general, electrical maintenance was properly planned, performed, and documented.
Workers were knowledgeable and capable of performing the assigned work activities.
Work observed in the switchyard was appropriately controlled and conducted in a manner
to minimize the possibility of an offsite power interruption. Field work was effective at
installing an emergent 4kV breaker modification, and assigned personnel appropriately
halted work when discrepancies were noted in the work package instructions.
Two violations (M4.3) regarding the conduct of a Unit 3 "modified performance discharge
test" for the 250 voe battery were identified. First, test personnel failed to comply with a
Technical Specification surveillance requirement to test in the "as found" condition.
Second, a corporate engineering memorandum, recommending testing the 250 voe
3
..
battery in other than the uas found" condition, was not evaluated in accordance with the
station's processes for procedural changes. The battery surveillance test problems
appeared isolated, but the ident,ified problems were significant with respect to test
procedural control, quality, and performance.
Maintenance Backlog
The action request (AR) backlog was relatively low and only contained tasks that would
not require a station work request to accomplish. The non-outage work request backlog
contained tasks that were appropriate to be worked while the units were operating. The
outage work request tasks were appropriately assigned to work during a unit outage. In
addition, reasonable explanations were provided for work tasks deferred to future outages.
Knowledge of the current maintenance backlog was good. In general, the maintenance
backlog was appropriately coded. so individuals responsible for work prioritization had a
sound data base. Some confusion existed in the data base due to incorrectly coded work
requests and work tasks that were included in the data base, but actual field work was no
longer required. The backlog of non-outage work request tasks was skewed in a direction
indicating positive progress was being made at reducing the oldest backlog items and
focusing attention on more recent equipment deficiencies.
Plant Support
Radiological Protection Performance
Some corrective actions to improve the control of licensed radioactive material within the
site's radiological protected areas (RPAs) have been adequately implemented. Actions
. scheduled for implementation after the current Unit 3 outage appeared sufficient to
improve licensee performance in this area. However, some training and repair issues
remained incomplete. In addition, the action to have the greeters address HRA issues was
not communicated to the greeters, and was not being conducted.
In general, radiological controls, ALARA initiatives, and job planning were effectively
implemented which contributed to the lower than projected dose for the outage to date.
Although some poor radiological work practices were observed, overall, there was good
effort to prevent loitering and unnecessary crew size.
One example (R 1.4) of a procedural violation regarding radiation worker practices was
identified for failure to wear personal dosimetry in accordance with station administrative
requirements. In addition, weaknesses were identified concerning poor housekeeping
practices.
4
REPORT DETAILS
Summary of Plant Status
Unit 3 was in the third week of a scheduled refueling outage. On April 11, 1997, three
days prior to the start of the inspection, Unit 2 entered a forced outage to repair cracked
switch blocks on safety-related 4kV Merlin-Garin circuit breakers. Both units remained in
outages throughout the inspection period.
I. MAINTENANCE
M1
Conduct of Maintenance
M 1 .1 Work Control
a.
lnsoection Scope
(
The team examined the procedures and processes associated with outage work
control. The team also monitored activities in specially designated outage
management work spaces.
b.1
Observations and Findings on Work Execution Center
The team reviewed the work execution center (WEC) instructions, interviewed WEC
staff, and monitored WEC activities. The WEC was responsible for authorizing the
conduct of work after assuring work package completeness, out-of-service
placement, and schedule adherence. The intent of the WEC was to reduce the
amount of traffic in the control room, thereby reducing control room operator
distractions. The WEC staff consisted of a supervisor, window coordinator, Unit 2
and 3 field supervisors, and an out-of-service (00S) supervisor. The WEC staff
were knowledgeable regarding the electronic work control system (EWCS), OOS
procedures, plant conditions, and outage schedules. The team observed the
processing and approval of work packages for replacement of brushes on both of
the Unit 2 recirculation pump motor-generators. The window coordinator reviewed
the packages and concluded that the contents were acceptable and met the
requirements of Dresden Administrative Procedure (OAP) 15-06, "Preparation,
Approval, and Control of Work Packages and Work Requests." The coordinator
also verified that the OOS had been placed and that the work gro1.,.1p supervisor was * *
signed on to the OOS.
The team reviewed the WEC instruction binder. The instruction binder consisted of
16 instructions and 2 notes which provided guidance on a variety of topics such as
valve and electrical lineup control, COS package control, procedure revision review,
pre-authorization of work packages, and electrical bus outage generic guidelines.
5
'('
c.1
b.2
The team noted that most of these instructions dealt with operation of the WEC.
However, in several cases, the instructions served as clarifications or detailed
guidance for implementation of approved procedures. Of note were instructions
concerning lineup and OOS package control, pre-authorization of work packages,
and electrical bus and motor control center outage generic guidelines. WEC
instructions were not reviewed, approved, or controlled. Use of uncontrolled
guidance for the implementation of approved procedures was also noted in the
work package preparation area and is discussed in Paragraph M1 .2.b.1.
Conclusions on Work Execution Center
The team concluded that the WEC was functioning effectively in reviewing and
approving work packages and meeting the objective of reducing control room
operator distractions.
Observations and Findings on Outage Control Center
The licensee elected to establish independent outage management organizations to
handle the Unit 2 forced outage concurrently with the Unit 3 refueling outage. The
licensee also elected to keep maintenance resources separated between the outage
organizations. The team monitored the operation of the Unit 2 forced outage "mini-
outage control center (OCC)," and the Unit 3 refueling outage OCC. During this
monitoring the team examined the functions of the positions established in the
OCC: the shift outage manager, the maintenance outage manager, the plant
support manager, and the outage risk manager. Members of the licensee's staff
filling these positions were interviewed to assess their understanding of outage
management and the processes involved. The team also consistently attended
regularly scheduled outage management meetings to evaluate coordination between
station departments and between Unit 2 and 3 outage management organizations.
While the licensee's decision to establish separate outage organizations was
fundamentally sound, problems were encountered in implementing this approach
early in the Unit 2 forced outage. The problems appeared to emerge from the rigid
approach to keeping maintenance resources separated. Most of the station's
maintenance resources were designated for the Unit 3 refueling outage with the
expectation that Unit 2 would remain in operation. A short outage schedule was in
place as required by OAP 18-02, "Unscheduled Force.d or Maintenance Outage
Planni.ng." However, there were no indications of any planning to provide resources
to implement that schedule in the event of a Unit 2 forced outage. Consequently,
when Unit 2 was shut down, adequate resources were not available to deal with
the scheduled work activities. Shortages were immediately evident in all
disciplines, most nqtably carpenters for scaffolding construction and radiation
protection (RP) technicians for area surveys. To immediately address the problem
RP technicians were pulled from Dresden Unit 1 and the craft assigned to the fix it
now (FIN) team were reassigned to Unit 2. Difficulties obtaining carpenters for
scaffold erection continued through Tuesday, April 1 5, until the two outage
managers met and developed a policy for sharing carpenters and other resources.
This was one example where outage coordination was initially ineffective.
6
{'
...
Early in the Unit 2 forced outage, it was recognized that two new "X-area"
[outboard main steam isolation valve room] coolers would not be onsite in time to
support the Unit 2 scheduled startup date. A decision was made to transfer a
cooler from the Unit 3 X-area. During a subsequent meeting on April 17, the topic
of which Unit 3 cooler was to be put in Unit 2 was discussed and outage staff
present at the meeting were unaware that the decision had been made, nor was the
outage staff aware of which cooler had been selected. That was another example
of ineffective coordination.
A major activity during the Unit 2 forced outage was to identify and repair a
condenser tube leak in the north water box. Coordination problems were evident
early on with problems in obtaining qualified individuals to erect scaffold, conduct
radiation and contamination surveys, and conduct confined space surveys. These
problems, along with the planning problems discussed in Section M1 .2.b.2,
impeded the job until a designated team with a project manager was *established.
After this team was established and a detailed schedule was prepared, condenser
repair activities proceeded more effectively. This was an additional example of
ineffective coordination.
Initial coordination problems between the two outage management organizations
were due, in part, to a lack of participation by the respective staffs in meetings held
by the other outage staff. The first day of the inspection the team noted that no
staff from the Unit .2 outage organization was present at the 6:30 a.m. Unit 3
outage status meeting, nor were staff from the Unit 3 outage organization present
at the 7:30 a.m. Unit 2 outage status meeting. The situation was identical atthe
1 :30 p.m. and 2:00 p.m. outage schedule review meetings. This was corrected the
next day and although some lapses occurred over the next few days, cross-
participation became routine and effective in identifying issues _with potential
overlap.
During the review of the outage organizations, the team found that the positions
established for the Unit 3 refueling outage were appropriate for dealing with the
major areas of outage management. For example, the plant support manager was
responsible for engineering and other plant support departments. The maintenance
outage manager was responsible for overseeing job status and resolving problems
identified by the work groups. The outage risk manager was responsible for
monitoring shutdown risk status and ensuring that shutdown risk assessments
were performed periodically and when required for changes in plant configuration.
This activity was especially important during the electrical lineup changes that were
necessary to support the 4kV breaker repairs. The shift outage manager was
responsible to the station manager for overall outage performance and monitored
schedule and budget performance, coordinated the efforts of the other outage
managers, responded to emergent issues, and coordinated resources and activities
with the Unit 2 outage manager. The Unit 2 forced outage organization was similar
in concept, but was not staffed as comprehensively. The team noted that the
individuals staffing these positions in both outage organizations understood the
assignments and the station's outage management program.
7
-(.
During the early part of the inspection, the team noted that regularly scheduled
meetings intended to either review outage status or examine the schedule were
generally unstructured, informal, unfocused, and did not address specific
accountability for assigned tasks. As the first week of the dual unit outage
progressed, the team noted changes in these meetings. The meetings became
more business-like and formal, discussions focused on specific tasks, individuals
were assigned to specific tasks, and accountability for completion was exacted.
This transition began with the Unit 2 outage meetings and by the beginning of the
second week, was occurring with the Unit 3 outage meetings.
- c.2
Conclusions on Outage Control Center
The team concluded that the OCC was functioning adequately and that it provided
the services that licensee management expected of it. Personnel staffing the OCC
understood the assigned positions, the objectives, and were generally supporting
the outage adequately. Coordination problems between the two outage
organizations were identified early in the first week of the inspection; licensee
corrective actions subsequently reduced the occurrence of these problems. The
team also concluded that there was a need to sharpen the focus of regularly
scheduled meetings.
M1 .2 Planning and Scheduling
a.
lnsoection Scope
The team reviewed the procedures and processes associated with planning and
scheduling, including work package preparation, individual task plans, and
scheduling systems used by the licensee. The team also assessed the licensee's
ability to maintain the established schedule. The team interviewed members of the
licensee's staff involved in the planning and scheduling processes. The team also
reviewed the new corporate-wide non-outage scheduling system which Dresden
was just beginning to implement.
b. 1
Observations and Findings on Work Package Preparation
The team reviewed OAP 15-06, *preparation, Approval, and Control of Work
Packages and Work Requests," Work Analyst Guide to Work Package Preparation,
EWCS Desk Top Instructions, and Maintenance Department Memo No. 100.14,
Dated August 30, 1996. In addition, the team reviewed the following work request
(WR) packages:
WR 960105540-01.
WR 970041990-01
U2 HPCI [high pressure coolant injection] Pump Suction
from Condensate Storage Tank Check Valve
Disassembly and Inspection
U2/3 Air Filtration Unit 4-lnch Charcoal Filter Halide
Testing
8
WR 950060862-01
WR 950065566-01
WR 960099060-01
WR 970044365-01
Bus 34 - Clean, Inspect Bus Bars, Wiring, Supports,
Insulation .
U3 Main Steam Line C High Flow Isolation Non-TS
Surveillances
Install Terminal Screws to A TWS [anticipated transient
without scram] Analog Trip System Cabinet A
Reinforce U2 Flued Head Anchor X-116B
No deficiencies were identified with any of the six packages
The team interviewed a work analyst and observed the preparation of a work
package for replacement of a solenoid valve on the Unit 2 high pressure turbine.
The team noted that the analyst was responsible for parts research, detailed work
instructions, radiation work permit (RWP) preparation, and evaluation of system or
component interactions and impacts. The analyst indicated that the majority of
time spent in package preparation was related to parts research, selection, and
justification. Considerable time was also expended in the research and
development of detailed work instructions. The station did not maintain a
comprehensive set of approved maintenance work instructions, consequently the
analysts were frequently required to provide detailed work instructions. The analyst
was also required to perform an impact analysis which examined the system
interfaces and interactions to identify possible alarms, actuations and interferences.
The analyst was familiar with the EWCS and the various data bases available and
consequently did not need to use the work analyst guide nor the desk top *
instructions (OTI). The analyst indicated that these guidelines were available and
were used extensively by recently assigned analysts still gaining familiarity with the
process.
The team reviewed both the work analyst guide and the OTls and noted that neither
of these documents were reviewed, approved, or* officially controlled. A pseudo
control (tracking copies) had been applied to the work analyst guide but was
unsuccessfUI. Three copies of the OTls were reviewed in the WEC; one was noted
to have hand-written revisions entered into it. This copy was immediately removed
by the WEC supervisor. The licensee had recognized the potential problems
intrinsic in allowing uncontrolled guidelines to be used to support implementation of *
approved procedures. A nuclear tracking system item had been previously opened
by the licensee to track resolution of this problem. The licensee reviewed the WEC
instructions, work analyst guide, and OTls and concluded that these guidelines had
not been used in the implementation of safety-related processes but recognized the
potential. The licensee committed to revise OAP 09-01, "Station Procedures," to
provide a clear definition for desktop instructions. The licensee also committed to
have working departments review the desktop instructions and initiate changes to
proceduralize the instructions as necessary.
9
Given the lack of comprehensive maintenance work instructions and the
consequent need for generating detailed work instructions, the team was concerned
with the potential for incorrect work instructions reaching the field. The team met
with work analyst supervision and reviewed statistics on packages returned to the
analyst. It was noted that packages were returned to the analyst for a variety of
reasons, most having nothing to do with errors in package preparation by the
analyst. Further discussions with work analyst supervision revealed that there was
no method for discriminating between reasons, no way to directly identify trends
from this data, and no way to determine what percentage of returned packages
were due to preparation errors. There was trending of parts problems, OOS
problems, and RWP problems from other data, but there was no direct correlation
between the two measurements.
The team noted that the work analyst organization had implemented a work
package quality control form in a effort to solicit feedback on the quality of work
packages. The form was not a station requirement; however, the intent was to
provide feedback from the shops after work packages were walked down. The
team noted that for the majority of work packages completed, the form had not
been completed nor was there any feedback on the quality of the package. As
such little or no benefit was being derived from the effort.
c.1
Conclusions on Work Package Preparation
The team concluded that work analysts were performing adequately; work
packages were generally of good quality and that the rejection rate, while not
precisely fixed, was not excessive. The team noted that during package*
preparation, the work* analysts were called upon to perform tasks which would
normally be considered engineering. Examples included parts evaluation and
system interaction analysis. The team also identified that a system of uncontrolled
documents was being used to enhance existing approved procedures. The team
concluded the licensee's existing approach to resolution of the uncontrolled
document to be reasonable.
b.2
Observations and Findings on Work Planning
The team reviewed plans for the three major work activities scheduled for the
Unit 2 forced outage and compared th.em to the actual performance of the work.
These comparisons revealed lapses in the licensee's planning process for each of
these tasks.
The licensee shut down Dresden Unit 2 after identifying that safety-related Merlin-
Gerin 4kV circuit breakers in both units had auxiliary switch blocks that were
cracked. A temporary modification was developed by engineering to correct the
problem. Planning to install this temporary modification included development of a
detailed "fragnet" to sequence the repairs to each breaker. It become apparent
early in the job that the plan had not properly considered all of the changes to the
electrical configurations of both units necessary to support the work. Major bus
outages were considered but other electrical lineup changes were not identified.
10
This resulted in frequent adhoc meetings between outage management and
operations to identify needed configurations, when, and how to get the plant into
those conditions. One example of the impact of this lapse was observed when a
bus drop would have deenergized the power for a diver's air compressor. This was
recognized just before the bus drop was to have taken place. The licensee
subsequently stopped work activities on this job and wrote a problem identification
form (PIF) to evaluate the problem. At the close of the inspection, the PIF was still
in process.
Planning for the Unit 2 condenser tube leak repair was also deficient. A specifically
responsible individual had not been designated, a detailed fragnet to identify the
sequence of activities had not been prepared, mainte_nance technicians had not
been trained on the use of the sonic "gun," the foam needed to confirm the leaking
tubes identified by the sonic gun had not been obtained, and the placing of OOS
and drawing a vacuum by operations were not well coordinated. The job faltered
until a dedicated team with a responsible project manager was selected. At that
point, a detailed fragnet was developed and the job began to move forward. Within
two days after the team was formed, the job was progressing efficiently.
Planning for the "X-area" cooler replacements did not consider the impacts on
Unit 3 nor did it establish which coolers should be transferred between the units.
This lapse was recognized by the Unit 2 outage staff and was resolved before it
impacted the job.
c.2
Conclusions on Work Planning
Initially, the forced outage schedule was prepared to address three major problems:
the switch block cracks in Merlin-Garin 4kV breakers, leaking "X-area" coolers, and
a condenser tube leak. Each of these activities exhibited elements of inadequate
planning or coordination problems.
b.3
Observations and Findings on Non-outage Scheduling
The team reviewed OAP 15-01, "Initiating and Processing a Work Request," OAP
04-02, "Dresden Preventive Maintenance Program Control," Nuclear Station Work
-Procedure (NSWP)-WM-08, "Action Request Screening Process," and NSWP-WM-
09, "Maintenance Work Scheduling Process Week E-5 to E + 1." The team also
reviewed schedules and reports associated with the non-outage scheduling process.
At the time of the inspection, the Dresden scheduling process was a 12-week,
system window program. System windows were scheduled in advance and as
work activities were identified they were assigned to the appropriate window. The
process began 12 weeks in advance of the date of work execution and contained
established milestones for preparation throughout the period. Reports and
schedules were published* periodically throughout the process to track progress.
The process was comprehensive and well:-structured; however, the team was not
able to assess its effectiveness because Unit 2 entered a forced outage on April 11 ,
1997r, three days before the inspection began .
11
c.3
b.4
The team also met with cognizant licensee staff to review and discuss a new
scheduling system commonly known as the "Braidwood initiative." This process
was defined in NSWP-WM-09 and focused on a period encompassing the five
weeks prior to the scheduled work execution to one week after scheduled
execution. As with the 1 2-week plan, there were established milestones for work
preparation. The licensee planned to integrate this new program into the current
12-week cycle and then phase out tracking the actions which took place between
weeks 12 and 5. Those actions would not be eliminated, but work preparation
would be expected to be at the same status when it entered the five-week schedule
as if it had tracked through the process from week 12 to week 5. Because the
program was in the early stages of implementation, the team had no opportunity to
evaluate the system's effectiveness.
Conclusions on Non-outage Scheduling
The licensee's present and future scheduling systems appeared to be well thought-
out and structured. With Unit 2 in a forced outage and a new program in the early
stages of implementation, the team chose to forego a historical review and focus
on activities in process. Consequently the team drew no conclusions with regard to
the effectiveness of either the 12-week or five-week programs.
Observations on Outage Scheduling
The team reviewed OAP 18-02, "Unscheduled Forced or Maintenance Outage
Planning," and OAP 18-04, "Management of Planned Outages." Both procedures*
were comprehensive and appeared to properly address the significant aspects of
outage planning. The team reviewed the licensee's outage scheduling program and
noted that it was essentially a standard P2 process, similar to that used by many
other utilities. The team reviewed several different versions of the licensee's
outage schedules and noted that durations and resource allocation were generally
appropriate. The team noted that the licensee's ability to execute the schedule was
hampered by several factors. Emergent work was the primary factor, as evidenced
by the need to respond to flued head anchor repairs on Unit 2 penetrations X-1168,
X-1098, X-115A, and X-111A, excessive vibration problems with a Unit 3 core
spray pump motor, and failure of a special control rod handling tool, which occurred
during blade swaps. In the latter case, the failure of the control rod tool led to a
licensee investigation and directly caused an hour-for-hour critical path loss. Other
factors which impacted the station's ability to work the schedule could be
collectively described as coordination issues. These included out-of-service
placement problems, parts availability, and overlap between jobs .in the same
physical location. Finally, resources appeared to impact schedule adherence. This
problem was the direct result of the Unit 2 forced shutdown. Because the station
had not planned how to staff a Unit 2 work force in the event of a possible dual-
unit shutdown, maintenance and plant support personnel were assigned Unit 3
tasks, and sufficient personnel were not readily available to perform Unit 2 tasks.
Where Unit 2 tasks had clear priority, resources were diverted from Unit 3
activities, which slowed down the Unit 3 activities. The situation was not expected
to be resolved until Unit 2 returned to power operation.
12
c.4
Conclusions on Outage Scheduling
The team concluded that the station's outage scheduling process was adequate but
that emergent work, coordination problems, and resource problems caused by not
planning how to staff a Unit 2 outage work force impacted schedule adherence.
M2
Maintenance and Material Condition of Facilities and Equipment
M2. 1 General Plant Conditions
a.
Inspection Scope (71707)
The team toured both Units 2 and 3 and observed maintenance and material
condition of plant facilities and equipment. Some of the areas observed were:
- Unit 3 drywall
- Unit 2 and 3 turbine deck
- Unit 3 *refueling deck
- Unit 2 and 3 HPCl/LPCl/Core Spray rooms
e Unit 3 MSIV X-room
- Unit 3 Steam Air Ejector room "A"
- Unit 2 and 3 Reactor Building (portions)
- Unit 2 and 3 torus area (El 512 ft.)
b.
Observations and Findings
In general, the observed material condition of most plant equipment was adequate;
however, some areas could substantially benefit from additional licensee attention.
In contrast some areas had received significant attention such as the emergency
service water vaults and adjoining corridors, the Unit 2 heater bay, and the reactor
building equipment drain tank room. Housekeeping was.adequate even.though the
ongoing outages posed a daily challenge.
b. 1
Unit 3 Main Steam Isolation Valve Room
The team identified minor deficiencies such as rust on bolts, piping and pipe flange
connections. There were also some minor structural deficiencies identified such as:
(1) A gland packing nut did meet the minimum thread engagement, and (2) the
team identified a large nut welded to feedwater flued head anchor support that was
not identified on the design drawing. The system engineer initiated Action
Requests (AR) 970037071 and 970037380 to correct the identified deficiencies.
b.2
Steam Jet Air Ejector Room-A
The team observed electrical duct tape wrapped around most piping and valve
flange connections in the Unit 3 steam jet air ejector (SJAE) Room-A. Discussions
with cognizant licensee personnel indicated that the electrical duct tape prevented
in-leakage into the system. The team was informed that this issue was previously
13
identified by the licensee. Work Request 960100762 had been generated to
remove the tape and repair any leaking flanges. The team noted that the material
condition of the nonsafety-related components in the Unit 3 SJAE Room-A was not
adequate to support efficient* plant operations.
The team also identified unapproved rigging attached to a piping system (U3 MS to
3A Relief to Main Condenser) in SJAE Room-A used to lift Valve 3-5406-A-501.
Use of the specific piping as an attachment point for rigging had not been
evaluated. The team found that rigging calculations had been performed on some
piping systems in the room; however, the observed pipe had not been included.
Subsequent calculations performed by the rigging engineer after the team's
observations indicated that the rigging of the valve to the pipe was acceptable.
c.
Conclusions of General Plant Conditions
The team concluded that the general material condition of the plant was adequate
considering a dual unit outage was in progress. Some areas of the plant had
received significant attention in the recent past as part of the licensee's overall
material condition improvement program. Some areas in the "balance-of-plant," or
nonsafety systems, were observed to be in poor condition. Corrective maintenance
documents were initiated, or already existed, to correct the noted deficiencies.
M2.2 Instrument Maintenance Facilities
a.
Inspection Scope (627041
The team inspected the Instrument Maintenance hot shop material condition and
general housekeeping of the facility.
b.
Observations and Findings on Instrument Maintenance Facilities
Housekeeping in the Instrument Maintenance hot shop area appeared to be
adequate. Separation existed between contaminated and non-contaminated tools.
A barrier was erected between contaminated and non-contaminated areas with
survey instruments readily available. The team observed adequate radiological
practices.
c.
Conclusions on Instrument Maintenance Facilities
The maintenance and housekeeping of the Instrument Maintenance hot shop was
adequate .
14
M3
Maintenance Procedures and Documentation
M3. 1 Safety Key Control
a.
Inspection Scope
The team observed an Instrument Maintenance Department (IMO) Control Systems
Technician (CST) perform a surveillance at a test cabinet containing safety-related
instrumentation.
b.
Observations and Findings
c.
On April 14 the team observed performance of Dresden Instrument Surveillance
(DIS) 1600-03, "Torus to Reactor Building Vacuum Relief Valve Trip Unit
Calibrations," Revision 7. The team observed an IMO technician at local analog trip
system (ATS) Panels 2202 (3) -73A and-738, located in the turbine building. Step
D.2 of DIS 1600-03 re*quired the IMO technician to obtain Safety Key CB-1 from
the operation shift supervisor. Step 1.8.a. of DIS 1600-03 required the IMO
technician to "Unlock AND remove trip rack card file locking bar associated with
MTU (Master Trip Unit) AND STU (Slave Trip Unit) ... " A review of the
Operations Department key control log identified that the IMO technician had not
checked out Safety Key CB-1 from the Operations Department; rather, the
technician used an unauthorized key stored in an IMO key locker. At the time of
this inspection, no IMO key control procedures existed.
Dresden Technical Specification 6.8.A required, in part, that written procedures
shall be implemented covering the activities referenced in Appendix A of Regulatory
Guide (RG) 1.33, "Quality Assurance Program Requirements (Operation),"
Revision 2, February 1978. Administrative and maintenance procedures were
referenced in RG 1.33.
Dresden Administrative Procedure (OAP) 7-14, Revision 8, "Control and Criteria For
Locked Equipment and Valves," described the criteria and controls needed for
issuing keys and operating locked valves and equipment.
Procedure OAP 9-13, Revision 6, "Procedural Adherence," described the
expectations regarding the use of and adherence to station procedures.
Contrary to the above, on April 14, 1997, an IMO technician obtained an
unauthorized safety key from an IMO key locker and not from the shift supervisor,
as required by procedure. Failure to properly implement DIS 1600-03, Revision 7,
Step 0.2,is an example of a Violation of Technical Specification 6.8.A
(50-237;249/97007-01 a)
Conclusions
The IMO technician did not follow station procedures to obtain Safety Key CB-1.
The IMO shop had an uncontrolled, unauthorized safety key accessible for general
15
use. The IMO shop did not have a key control procedure for either safety-related or
nonsafety-related keys.
M3.2 Independent Verification
a.
Inspection Scope
b.
The team observed an IMO technician perform a surveillance on the reactor building
ventilation stack flow monitor.
Observations and Findings
On April 18 the team observed the performance of DIS 5700-14, "Reactor Building
Vent Stack Flow Monitor Functional Test," Revision 1. The team observed two
contract IMO personnel performing the test. Step 1.8.c required an independent
verifier to "witness" the lifting of an electrical lead from a terminal block. The team
requested records to verify that the contract personnel were trained to perform
independent verification. The IMO superintendent responded that independent
verification training for the twelve IMO contract personnel had been performed
verbally in the shop and that no records existed to document the training. In
contrast, the station provided information that showed twenty Electrical
Maintenance Department (EMO) contract personnel received formal, documented
training regarding independent verification. A review of OAP. 07-27, "lndepenpent
Verification," Revision 13, identified a difference between the station's *
administrative procedure requirements for independent verification, and what was
implemented in the Instrument Maintenance Department procedures. The concept
of "witnessing" an event was not defined in either the departmental or station
procedures. Conversations with station management identified that IMO procedural
requirements to "witness" were actually a "second check" as defined in the
station's administrative procedures. Specifically, OAP 07-27, "Independent
Verifications," Step F. 1, required that independent verifications be performed on all
lifted leads involving Technical Specification or safety-related equipment. In
addition, the team noted that an "apart in time" independent verification was not
performed as defined by station procedure OAP 07-27.
Dresden Technical Specification 6.8.A required, in part, that written procedures
shall be implemented covering the activities referenced in Appendix A of Regulatory
Guide (RG) 1.33, "Quality Assurance Program Requirements (Operation),"
Revision 2, February 1978. Administrative and maintenance procedures were
referenced in RG 1.33.
Dresden Administrative Procedure (OAP) 07-27, "Independent Verifications,"
Revision 13, Section F.1, required that independent verification be performed on all
lifted leads involving Technical Specification or safety-related equipment.
Contrary to the above, on April 18, 1997, a "second check" was performed in
accordance with DIS 5700-14, "Reactor Building Vent Stack Flow Monitor
Functional Test," Revision 1, Step 1.8.c. That surveillance instruction required an
16
..
independent verifier to "witness" the lifting of a safety-related electrical lead from a
terminal block versus the independent verification required 'by OAP 07-27. Failure
to properly implement OAP 07-27 is an example of a Violation of Technical
Specification 6.8.A (50-237;249/97007-01 b).
c.
Conclusions
A "second check," not an "independent verification" was performed duri.ng DIS
5 700-14. IMO and station administrative procedures were not in agreement
regarding the requirements for independent verification. The training of contractors
on the requirements for independent verification was inconsistent.
M4
Maintenance Staff Knowledge and Performance
M4. 1 Instrument Maintenance Performance
a.
Inspection Scope (62704)
The team observed 24 field maintenance activities performed in the Instrument and
Controls areas. Team observations included various maintenance activities such as
remounting of components, calibration of pressure switches, Technical
Specification surveillances, functional tests of level switches, a vent stack flow
monitor functional test, trouble-shooting and repair of the Unit 2 drywall continuous
air monitor (CAM), post-LO CA containment hydrogen and oxygen analyzer
calibration, turbine trip functional tests, calibration of a resistance temperature
detector, source range monitor rod block calibration, reactor feedwater loop
temperature calibration, and local power range monitor (LPRM) pre-installation
insulation resistance and breakdown voltage acceptance checks.
The team observed all or part of the following work request (WR), dresden
instrument surveillance (DIS) or Dresden instrument procedure (DIP) activities:
DIS 1600-03
Torus to Reactor Building Vacuum Relief Valves Trip Unit
Calibration
WR 940097988-08 Replace Tripping Function Yarway Reactor Water Valve Switch
DIS 2400-02
DIS 5700-04
DIS 0263-07
Post-LOCA Containment Hydrogen and Oxygen Analyzer 18
Month Calibration and Maintenance Inspection
Reactor Building Vent Stack Flow Monitor Functional Test
A TWS RPT /ARI [recirc pump trip/alternate rod insertion] and
ECCS Level Transmitters Channel Calibration Test and EQ
Maintenance Inspection
WR 950060521-01 3A LPCI PMP MOTOR SURVEILLANCE
17
_,
DIS 0250-01
Main Steam Line High Flow Isolation Switch Calibration
WR 960087265-01 Correct Switch Vertical Mounting Position and Calibration
DIS 9900-01
DIS 0700-10
DIS 5600-05
DIS 2300-08
Computer Controlled Analysis Input Instrument Calibration
Source Range Monitor (SRM) Rod Block Calibration
Turbine Trips Functional Test
Units 2/3 Contaminated Condensate Storage Tank and Unit 2
Torus Level Switches Functional Test
WR 950062900-02 Send Out for Refurbishment and Calibrate
WR 970001564-01 2A Off Gas Condenser Normal Level Control
DIS 0202-04
Recirculation Pump MG Set Scoop Tube Control Rod Actuator
Assembly Upper Mechanical and Electrical Stop
WR 960096144-01 Clamp MG Set Scoop Tube and Perform DIS 0202-04
WR 970043047-01 Troubleshoot and Repair Unit 2 OW [drywall] CAM Pegged
Low
DIS 1700-17
DIS 1400-04
DIS 0287-01
NMC Drywall Continuous Air Monitor Preventive Maintenance
and Calibration
Emergency Core Cooling System Fill System Alarm Pressure
Switches
Automatic Depressurization System CS and LPCI Pumps
Discharge Pressure - High (Permissive). Channel Calibration and
Chann~I .Functional Test
WR 970005193-01 River Temp Recorder Calibration
DIS 1600-04
DIP 0700-06
DIS 1600-10
ECCS Drywall Pressure Switches Channel Calibration and
Channel Functional Test
LPRM Pre-Installation Insulation Resistance and Breakdown
. Voltage Acceptance Checks
Drywell and Torus Pressure Instrumentation Channel
Calibration and EO Surveillance for Age Related Degradation
18
b.1
Observations and Findings regarding Instrument Maintenance Technicians
Adherence to Procedures
The team observed two instances where IMO technicians did not follow approved
procedures during the conduct of maintenance:
During performance of DIS 1600-03, "Torus to Reactor Building Vacuum
Relief Valves Trip Unit Calibration," Revision 07, the surveillance performer
did not turn off the power supply to the test modules as directed by the
procedure to secure the equipment in a safe state. (The team identified the
condition to the cognizant supervisor.) The technical concern was if the
equipment remained energized, then a false trip might occur when the
equipment was returned to service.
During performance of DIP 0700:-06, "LPRM Pre-Installation Insulation.
Resistance and Breakdown Voltage Acceptance Checks," the surveillance
performer used Revision 2 of DIP 0700-06; however, that procedure had
been revised and the current "Revision 3" version should have been utilized.
OAP 09-13, "Procedural Adherence," Revision 06, required the user to verify
that the procedure was the current revision or a temporary change. The
licensee generated a problem identification form (PIF) to document that the
maintenance activity was not performed with the current revision and to
document the corrective actions.
Dresden Technical Specification 6.8.A required, in part, that written procedures
shall be implemented covering the activities referenced in Appendix A of Regulatory
Guide (RG) 1.33, "Quality Assurance* Program Requirements (Operation),"
Revision 2, February 1978. Administrative and maintenance procedures were
referenced in RG 1.33.
Failure to turn off the power supply to a test module during performance of
DIS 1600-03; "Torus to Reactor Building Vacuum Relief Valves Trip Unit
Calibration," Revision 07, and failure to verify the proper revision level of DIP
0700-06, "LPRM Pre-Installation Insulation Resistance and Breakdown Voltage
Acceptance Checks," during performance of surveillance testing are examples of a
of a Violation of Technical Specification 6.8.A (50-247/249-97007-02a&b).
c. 1
Conclusions on Instrument Maintenance Adherence to Procedures
With the exception of the instances noted above, the IMD staff was generally
following procedures. The team observed that the IMD had the resources and
capability to improve procedural adherence.
b.2
Observations and Findings on Instrument Maintenance Surveillance Performance
During performance of Unit 2 DIS 0202-04, Revision 01, "Setting Recirculation
Pump MG Set Scoop Tube Control Rod Actuator Assembly Upper Mechanical and
Electrical Stop," Step 1.11.j.3 through 7, the indicated switch contact states were
19
reversed in the procedural steps. The closed state was indicated as open, and the
open contact state was indicated as closed. After consultation with the IMO
supervisor, the technician proceeded with the maintenance with the supervisor's
approval.
During the performance of Unit 2 DIS 1600-04, Revision 14, "ECCS [emergency
core cooling system] Drywall Pressure Switches Channel Calibration and Channel
Functional Test," on page 72 of 81, the procedure erroneously referred to PS
3-1632-B, when it should have been PS 2-1632-B. After consultation with the IMO
supervisor, the technician continued the surveillance with the supervisor's approval.
The table on the page 72 was appropriately marked as not-applicable.
During the performance of Unit 3 DIS 5600-05, Revision 10, "Turbine Trips
Functional Test (Not Tested in Another Procedure)," the technician found that the
temperature switches were out-of-calibration. The technician appropriately
generated two PIFs to identify the out-of-calibration.
During the performance of Unit 3 reactor low level ECCS initiation, Work Request
940097988-08, the technician found that the work task did not specify the correct
machine screw size. The technician appropriately generated an engineering change
notice to identify the correct size screw.
c.2
Conclusions on Instrument Maintenance Surveillance Performance
The IMO maintenance and surveillance activities observed were adequately
performed. When problems were encountered by IMO technicians, supervisors
were there to render assistance to the technicians to complete the jobs.
b.3
Observations and Findings on Instrument Maintenance Preparation
The team observed pre-job briefings for IMO maintenance activities and the
coordination with the Operations Department on specific maintenance tasks. The
team also observed the pre-job walkdown of the job, review of the work package,
. review of the radiological conditions for the job location; and verification of the
revision of the procedures used.
The pre-job briefings were performed per OAP 15-06, Revision 17. The supervisors
conducted a step-by-step briefing of the procedures for the crews performing the
maintenance tasks. The supervisors reviewed the out-of-service requirements of
the job with the crews. The team noted that, for the activities observed, the pre~
job briefings were well conducted.
c.3
Conclusions on Instrument Maintenance Preparation
The team concluded that the job preparation for the activities observed were
appropriate .
20
M4.2 Mechanical Maintenance Performance
a.
Inspection Scope (62703>
The team observed all or portions of the following 23 Mechanical Maintenance
Department work activities:
WR 960100729-01
WR 950065976-01
. WR 960049153-01
WR 940096369-01
WR 950093031-03
WR 960099129-01
WR 960034237-01
WR 950064442-12
WR 950064442-11
WR 950063630-01
WR 950046326-01
WR 950064530-01/02
WR 950061535-01
WR 950061535-02
WR 950061535-03
WR 950061535-04
Trouble shoot and Repair Standby Liquid Control Pump
3-11028
Replace HPCI Turbine Flexible Oil Lines in Oil Reservoir
Repair Stem for Feedwater Heater Normal Level Control
Valve
Replace Extraction Steam Nozzles for Feedwater Heater
Determ and Reterm Limitorque and Limit Switches and
Perform Signature Trace
Disassemble Outboard Turbine Bearing for Unit 3 HPCI
Turbine
Unit 3 HPCI Drain Pot Line Replacement
Replace Valve Trim and Actuator for 3-0642-B
Modification, Replace 3-0642 Valve Trim Assembly
Disassemble Low Flow Feedwater Regulator Valve
(3-0643), Inspect/Repair Valve Seat
Disassemble/Reassemble MSIV for Installing New Liner
Design
Replace Air Diaphragm on Scram Valve 34-31
Replace Accumulator Scram.:Water Cylinders with
Stainless Steel Accumulator
Repair Body to Bonnet Leak and Inspect Valve HCU 42-
31 Cooling Water Inlet Valve
Replace Air Diaphragm on Scram Valves 42-31 Inlet
Valves
Replace Air Diaphragm on Scram Valves 42-31 Outlet
Valves
21
*
b.
b.1
WR 890062254-02
WR 960118148-02
WR 960118198-03
WR 970044365-01
WR 950107745-02
WR 950107745-01
WR 940097084-03
Install Gas Saver Lance on Pipe to Condensate Booster
- Pump "3B"
Repair Existing Monel Stub Plate for 3B
LPCl/Containment Cooling Heat Exchanger
Repair Existing Monel Stub Plate for 3A
LPCl/Containment Cooling Heat Exchanger
Reinforce Flued Head Anchor Support for Penetration X-
116B
Repair Steam Leak thru the Seat of 3A Off Gas
Preheater PCV 3-5424-A Bypass Valve
Repair Steam Leak thru the Seat of 3A Off Gas
Preheater PCV 3-3099-46 Outlet SV
Repair of Guide Rails for Unit 3 LPCI II Full Flow Bypass
Test Inboard MOV No. 01208
Observations and Findings on Mechanical Maintenance Performance
In general, the team found work performed under the above activities to be
conducted in a professional and thorough manner. Maintenance personnel observed
were experienced and knowledgeable of the assigned tasks. The team frequently
observed supervisory and system engineering oversight of the job activities.
Quality control personnel were also present when required by the work package
and procedure. When applicable, appropriate radiation control measures were
established or in place.
Observations and Findings on Reactor Feedwater Regulating Valves
The team observed work activities for the Unit 3 reactor feedwater regulating
valves. The work being performed was a modification initiated by the licensee as
corrective actions implemented to improve the reliability of the feedwater system.
The team noted that the licensee was in the process of purchasing a software
package "Valve Packing Optimization Program (VPOP). This software could reduce
manhours, and eliminate the possibility of incorrectly selecting the proper size
packing for any particular size valve at the Dresden site. This program could also
eliminate extra burden from work analyst. The team noted the use of VPOP was an
excellent tool for valve maintenance.
The team observed various portions of work being performed on the reactor
feedwater regulating valves. The team observed maintenance technicians install an
actuator on Valve 3A, and take measurements for the installation of Valve 3B
internals. The work being conducted was a modification to improve feedwater
22
b.2
regulating valve reliability which was also a long term corrective action fix. The
work was being conducted by a contracted valve maintenance group. For the
activities observed, workers were knowledgeable of the work being conducted, and
work was performed in accordance with procedures. Supervisory oversight was
good.
Observation and Findings on Main Steam Isolation Valve Repair
The team observed repairs to Main Steam Isolation Valve (MSIV) 3-0203-28. The
team observed removal of the internals from the valve and noted that the
radiological controls were good during breach of the system. The team* observed
good supervisory oversight. Maintenance technicians were knowledgeable and
experienced.
In addition, during the above activity observation, the team noted the following:
Poor radiological practices by a maintenance worker (carpenter) in the MSIV
X-room was observed by the team. The maintenance worker did not have
the appropriate minimum protective clothing (scrubs) as required by OAP
12-35, *oonning And Removal Of Routinely Required Radiological Protective
Clothing And Protective Clothing Guidelines," Revision 4. The team
questioned th.e maintenance worker about the proper protective clothing.
The maintenance worker wore blue jeans instead of scrubs while placing
tags on a scaffold. Procedure OAP 12-35 required minimal protective
clothing to be worn when conducting work activities, and the team believed
that crawling over pipe to hang tags on scaffold was work. Discussions
with various radiation protection technicians indicated inconsistericies in how
the procedure was being implemented. It was also not clear what
management expectations were with regards to the minimum protective
clothing requirements. The team informed licensee management of this
issue.
During observation of maintenance activities in the MSIV X-room, the team
observed the following:
On April 17, 1997, foreign material exclusion (FME) controls were not
adequate in the MSIV X-area as evidenced by protective clothing, rubber
shoe covers, plastic protective clothing, rags and rubber gloves laying in
disarray throughout the area.
On April 17, 1997, electrical maintenance personnel were observed not to
replace a valve cover for MOV 3-220-3 for about 2 1 /2 hours after leaving
the area, which left the limit switches and electrical connections
unprotected.
Dresden Technical Specification 6.8.A required, in pa.rt, that written procedures
shall be implemented covering the activities referenced in Appendix A of Regulatory
Guide (BG) 1.33, "Quality Assurance Program Requirements (Operation),"
23
b.3
- -
Revision 2, February 1978. Administrative and maintenance procedures were
referenced in RG 1.33 .
Dresden Administrative Procedure (OAP) 03-23, "Foreign Material Exclusion
Program," Revision 8, required in part: O) FME controls are required for any work
activity, modification, test, inspection or sampling that involved opening a system
or component; (2) extra protective clothing, equipment, tools and parts not
immediately used that are brought into an FME area will be properly contained while
no work was in progress, and (3) Covers must be placed on all systems breached
when the opening was left unattended.
- Failure to maintain adequate FME controls in the Unit 2 main steam isolation valve
room on April 17, 1997, as discussed in the two instances above is an example of
a Violation of Technical Specification 6.8.A (50-237;249/97007-03a&b).
The team also identified several valves that did not appear to be in accordance with
the HPCI system valve checklist or the inaccessible locked valve checklist. The
HPCI system checklist indicated that Valve 3-2399-87 and 3-2301-97C should
have been closed and locked. Actual field configuration indicated that Valve
3-2399-87 was not locked. The revised inaccessible locked valve checklist deleted
these valves from being locked; however, Valve 3-2301-97C was closed and
locked in the field configuration. The team discussed this issue with the cognizant
licensee engineer, and discussions indicated that the noted problem had been
identified previously and corrective action was in the progress of being
implemented. The team was informed that the inaccessible locked valve checklist
had been revised as part of the completed corrective action. Further, the team was
informed that all corrective actions were required to be completed prior to the
completion of the current outage (03R14). The team noted however, that no plan
had been implemented at the time of the inspection to complete the proposed
corrective actions. Corrective action began in March 1995 and were sched.uled to
be complete this outage (03R14).
Observations and Findings on Control Rod Drive Scram Discharge Valve Repair
The team observed General Electric technicians remove old air diaphragms and
install new diaphragms in Scram Discharge Valves 126 and 127. The team
questioned the technicians on various portions of the work package and
instructions. The technicians were knowledgeable and professional, and there was_
good supervisory oversight of the work activities.
During a plant tour, the team observed old and new control rod drive scram
solenoid pilot valves in an unspecified FME Zone area in Unit 2. The new valves
were to be installed in Unit 3. The new valves were not fully protected at the pipe
ends to prevent dirt and debris from entering and degrading the valves. Failure to
follow the foreign material exclusion (FME) requirements of OAP 03-23 for the CRD
scram solenoid pilot valv~s is another example of a Violation of Technical
Specification 6.8.A (50-237;249/97007-03c).
24
b.4
b.5
Observations and Findings on Condensate Booster Pump Piping Repair
The team observed maintenance technicians perform a hydrostatic test on the gas
saver lance on pipeline B. The technicians followed procedures; however, the
technicians indicated that during a previous hydrostatic test, the post calibration of
the pressure gage indicated the gage was well out of tolerance. The team
questioned whether a PIF was written because the gage could have been used on
safety-related equipment. The PIF was not written by the individual technicians
until prompted by the team, which indicated some reluctance or lack of knowledge
of the involved technicians on when to initiate a PIF.
Observations and Findings on Low Pressure Coolant Injection/Containment Cooling
Heat Exchanger Repair
The team observed maintenance personnel perform welding activities on Unit 3 low
pressure coolant injection (LPCI) and/or containment cooling heat exchanger "A"
and "B." Maintenance technicians were repairing the divider plate in both heat
exchangers due to degradation. The team observed welding of the monel stub
plate on both heat exchangers. On April 22 the team identified two instances
where procedural requirements were not fully adhered to:
During welding of FW 1 and FW 2 for "38" heat exchanger, the welder did
not verify interpass temperature as required by the weld data sheet and
Weld Procedure NSWP-W-01, "ASME and ASME 831 . 1 Welding,"
Revision 3. Discussions with maintenance engineering personnel performing
the work indicated that interpass temperature was verified based on welder
experience. The weld data sheet to the work package specified a maximum
interpass temperature of 700°F. The maintenance technicians at the work
location did not verify the interpass temperature. Also, the technicians did
not have a temperature stick or pyrometer at the work location to verify
interpass temperature.
Through discussions with the cognizant welding engineer, the team learned
that the expectation for how to determine interpass temperature was at the
discretion of the welder. Upon completion of this discussion, the cognizant
welding engineer initiated a memorandum dated April 23 to all Dresden
welders indicating when interpass temperature was specified, interpass
temperature must be verified upon completion of a weld pass.
Dresden Technical Specification 6.8.A required, in part, that written procedures
shall be implemented covering the activities referenced in Appendix A of Regulatory
Guide (RG) 1.33, "Quality Assurance Program Requirements (Operation),"
Revision 2, February 1978. Maintenance procedures were referenced in RG 1.33.
Failure to verify interpass temperature as required by the weld data sheet and Weld
Procedure NSWP-W-01, is an example of a Violation of Technical Specification 6.8.A (50-237;249/9707-04a).
25
-,
b.6
During the second shift, maintenance technicians were observed performing
welding activities on the "38" heat exchanger monel stud plate without the
proper work package. The work package had been retrieved from the area
- for revision by the work analyst; however, a minimal work document was
left for the maintenance personnel to continue work. Procedure OAP 15-06,
"Preparation, Approval, and Control Of Work Packages and Work Requests,"
Revision 17, required at a minimum, a copy of the work request for portions
of work being performed that day. The minimal work document was not
sufficient for the work activities being performed on the heat exchanger 38
monel stud plate. The maintenance superintendent immediately stopped
work and initiated a PIF.
Failure to have the appropriate work document as required by OAP 1 5-06 is another
example of a Violation of Technical Specification 6.8.A (50-237;249/97007-04b).
Observations and Findings on Unit 2 Flued Head Anchor Support
The team observed welding activities performed. on Unit 2 flued head anchor
support 2-1600-X-1168. The licensee had identified that several welds on this
containment penetration anchor frame were outside FSAR stress limits. Therefore,
Design Change E12-2-97-206 was implemented to reinforce the welds on the
support. The team found that maintenance personnel did an. excellent job in
surveying the proposed work activities prior to performing any welds. Welders
were qualified to perform the welds made in accordance with the welder
qualification matrix. Overall, the maintenance technicians did a good job.
However, the team noted that Design Change Drawing 8-2088, Revision A, was
very difficult to understand.
The team also noted through subsequent discussions with the cognizant welding
engineer that the licensee had identified that incorrect preheat was specified in the
work instructions by the work analyst. Preheat should have been 1 50°F instead of
the noted 50°F. For this task, the team observed that: ( 1) work analyst may have
been tasked with responsibilities that engineering could more appropriately p_erform,
such as specifying preheat requirements, and (2) expediting emergent work
activities without adequate review appeared to have resulted in some poor work
documents.
b. 7
Observations and Findings on Unit 3 Off Gas Preheater Pressure Control Valve
Replacement
The team observed maintenance technicians perform Weld 5 and Weld 1 on the 3A
Off Gas system Pressure Control Valves 3-3099-46 and 3-3099-48 and associated
pipe attachments. Fitup was performed properly, and the welders were
knowledgeable of the work requirements and the procedure used. The team also
verified the welders were qualified in accordance with the welder qualification
matrix. The work activity was conducted in an excellent manner.
26
b.8
c.
Observations and Findings on Unit 3 LPCI Valve Repair
The team observed maintenance technicians install valve internals to Motor
Operated Valve (MOV) 01208. This valve was apparently having problems with the
guide rails .. Maintenance technicians performed an excellent job installing the valve
internals. Procedures and instructions were followed *. The team found that the
maintenance technicians performing the work were both ComEd and contractor
technicians. For the work observed, the assigned craft worked well together. The
team also observed quality control perform FME verification. Discussions with the
technicians indicated that quality control had written a PIF on the valve disk
because of deficiencies identified during a dye penetrant exam. The team was
informed by the licensee that engineering conducted an evaluation, and determined
the disk to be acceptable.
General Conclusions on Mechanical Maintenance Performance
Mechanical Maintenance activities were generally conducted in a thorough and
professional manner. The team identffied two specific violations with multiple
examples of each. The violations involved poor FME controls; inadequate welding
processes; and performance of safety-related work without a sufficient work
package at the work site. In addition, some poor work practices were identified
with regard to minimum protective clothing requirements and unanalized rigging of
components to nonsafety piping systems.
M4.3 Electrical Maintenance Performance
a.
Inspection Scope (62703)(62705)
The team observed or reviewed all or portions of the following 14. Electrical
Maintenance Department work activities:
WR 970042480-01
WR 970042481-01
WR 950018438-01
WR 960027460-01
WR 960066023-01
WR 970020861-01 *
Addition of Restraining Straps on GGS 4 KV Circuit
Breakers Using Design Change (DCN) 001086E
Addition of Restraining Straps on GGS 4 KV Circuit
Breakers Using DCN 001086E
250V DC Station Battery Cell Maintenance Unit 3
Unit 3 250V Station Battery Modified Performance Test
125 V Molded Circuit Breaker Inspections and Testing
Using Procedure SMP-E-01
Seal Various Penetrations in Technical Support Center
Unit 3 Six Year Exciter and Generator Inspections
27
,..
WR 960098283-01
WR 960097439-01
WR 960110681-01
WR 950060779-02
WR 950060659-01
WR 970046098-01
Temp Alt 11-07-97
Replace Limit Switches on 1 A and 1 C Main Steam
Isolation Valves and Perform Surveillance Check
Afterwards
Inspect Ground Device # 10 and Shim if Required
Repair Motor Oil Leaks to the 2A Reactor Recirculation
Pump
Perform Preventive Maintenance and Inspect the Unit 3,
"B* Channel, Reactor Protection SCRAM Contacts
Perform Preventive Maintenance on the Contactor to a
DC Motor for the HPCI Condensate Storage Tank
Return Valve
Troubleshoot and Repair a Full Negative Ground in the
Unit 3 125 V DC System
345 KV Bus 6 Bypass for New Line 2311
b. 1
Observations and Findings on Switchyard Work on 345 KV Lines (All Units)
The licensee initiated a modification to install a 345 KV tie line between the
Dresden and Collins (fossil plant) station switchyards. To support work on the
modification, the licensee prepared a temporary wood pole structure to bypass
345 KV Bus 6 and keep the Dresden station blue bus ring intact. The team
observed work in the switchyard, reviewed associated documentation, and
discussed the job with licensee personnel.
While watching modification activities in the field, the team observed that the
licensee had installed a temporary security fence (within the main switchyard
boundaries) to direct vehicle and heavy equipment traffic away from vulnerable
switchyard structures. Discussions with the licensee personnel revealed that, prior
to the teams' arrival on site, the crew performing the task was required to perform
five practice setups and removals of the 85-foot long wooden poles prior to
commencing actual work in the switchyard. The team observed portions of the
actual switchyard work and identified no concerns. Through discussions with
cognizant licensee personnel and review of the associated documentation, the team
noted that the plant onsite review committee (PORC) had twice rejected the
modification package plans prior to recommending approval of the project.
c. 1
Conclusions on Switchyard Work on 345 KV Lines (All Units)
The team concluded that the work performed in the switchyard was appropriately
controlled and conducted in a manner to minimize the possibility of an offsite power
28
interruption. The team considered the PORC's rejection of the initial package to be
a positive indication of a strong and independent review process.
b.2
Observations and Findings on Modifications to 4KV Circuit Breakers Auxiliary
Switches <Unit 2 and 3)
On April 10, 1997, the licensee shut down Unit 2 after declaring some Merlin-Garin
4KV circuit breakers inoperable. Licensee personnel had discovered cracks in the
offsite power supply breaker to the diesel emergency bus and declared all offsite
power supply busses inoperable. The team observed in-plant temporary repairs to
the breakers and reviewed the associated documentation.
The team observed in-plant repair activities to address cracks that were discovered
in some of the auxiliary switches of the 4KV Merlin-Garin breakers. The team
observed electrical maintenance, quality control, and engineering personnel at the
job site; all appeared knowledgeable of the issue, and the team observed effective
communication and coordination between the groups when the work activities took
place. However, the work was suspended on the breakers due to licensee
identified concerns with the work instructions. Discrepancies were noted between
engineering documents and work package instructions in the field. Specifically, not
all PORC comments were incorporated into the work package and inconsistencies
existed in the inspection criteria used to accept the work. The licensee initiated a
problem identification form (PIF) to document the work package deficiencies. The
work package instructions were subsequently clarified and the team identified no
further concerns with the work.
c.2
Conclusions on Modifications to 4KV Circuit Breakers
The team concluded that personnel in the field worked effectively to install the
breaker repair modification and that licensee personnel appropriately halted work
when discrepancies were noted in the work package instructions. However, the
team also concluded that the initial work package was poorly planned.
b.3
Observations and Findings on Unit 3 Station 250 VDe Battery Modified
Performance Discharge Test
The licensee conducted a modified performance test (MPT) of the Unit 3 250 voe.
battery. The test was intended to satisfy the requirements of both a service test
and a performance test. The team observed portions of the MPT, reviewed the
procedures, and followed up on questions developed during the reviews.
The team observed test preparations and portions of the testing activities. The
performance of the test was delayed because the required test equipment was not
initially available to support testing. The delay was due to the failure to have
appropriate cable connectors for the load banks available onsite when the licensee
initially was scheduled to conduct the modified performance test.
29
Test performance and results:
At the start of the inspection, the team developed concerns regarding the licensee's
testing methodology of the Unit 3 250 voe battery. The concerns centered around
the testing of the battery in the .. as found* condition. The licensee performed a
MPT as allowed by Technical Specifications (TS); however, the TS stated that the
modified performance discharge test satisfied the requirements of both a service
test and the performance test [defined in IEEE 450-1995).
Prior to testing the battery using the service test methodology I the licensee was
restricted from testing the battery in any condition other than the *as found"
condition. The MPT was required to meet the initial conditions of the service test,
and performance of maintenance prior to the test would invalidate the "as found"
condition of the battery.
Substantial maintenance was performed* on the station battery prior to the MPT.
The maintenance included:
o
Replacement of cell Number 48
Replacement of inter-tier cables
Replacement of a large number of battery post seals
Cleaning of the battery connection posts
The team's review of battery data showed that replacement of cell Number 48 was
due to the identification of a small crack in the battery housing and not due to a
low voltage of the cell. In addition, cleaning of the battery posts improved the
inter-cell resistance values, but only by about 20 percent. The team, assisted by *a
Region Ill specialist inspector, concluded that the above maintenance pre-
conditioning of the station battery did not make a significant difference to the
results of the test; however, pre-conditioning did occur.
The licensee's performance of the pre-test maintenance was contrary to the TS
requirement to perform the MPT in the "as foundR condition, i.e., a MPT was
intended to meet the requirements of a service test. Initially, cognizant licensee
personnel believed that performance of the pre-test maintenance activities did not
make a significant difference in the battery's ability to perform its function;
therefore, the licensee believed the pre-test maintenance did not violate the "as
foundR requirement.
In addition to the pre-test maintenance, the Unit 3 250 VOC battery was given a
222-hour equalize charge starting on April 3, 1997, in anticipation of the scheduled
MPT. The equalize charge on the battery just prior to the test discharge was
performed in accordance with Work Request 950018438-04, "Perform Equalize
Charge." The equalize charge work request was apparently initiated to satisfy
Dresden Electrical Surveillance (DES) 8300-20, "Unit 3 250 Volt Station Battery
30
Modified Performance Test," Revision 02, Step G.3, which stated: "Equalize
charge is recommended within 30 days prior to the test, but
NOT within three
days prior to this test."
Step G.3 of DES 8300-20 was essentially a verbatim translation of the Institute of
Electronic and Electrical Engineers (IEEE) 450-1995, Section 6.1 "Initial
Conditions," Requirement a), which stated .. Equalize the battery if recommended by
the manufacturer and then return it to float for a minimum of 72 h, but less than
30 days, prior to the test." Further, Requirement b) of IEEE 450-1995,
Section 6.1, stated to "Check all battery connections and ensure that all resistance
readings are correct for the system."
However, IEEE 450-1995, Section 6.6, "Service Test," stated, in part, "The initial
conditions shall be as identified in 6. 1 [omit requirement a), perform requirement b)
but take no corrective action unless there is a possibility of permanent damage to
the battery and perform requirements c) through f))." Therefore, DES 8300-20,
Revision 02, Step G.3, was in error and should have cautioned the test performers
nQ1 to perform an equalize charge. The error in DES 8300-20 was apparently made
when the MPT procedure was originally written in response to the licensee's
endorsement of the 1995 IEEE standard, and a similar step in the old "performance
test" procedure was carried over to the MPT procedure.
Technical Specification 4.9.C.5 stated, in part, that at least once per 60 months,
verify that the battery capacity is at least 80 percent of the manufacturer's rating
- when subjected to either a performance test or a modified performance test
discharge. The modified performance discharge test satisfies both the service test
and performance test and therefore, may be performed in lieu of a service test.
Since the MPT was subject to the same criteria as a service test, the test was
required to be performed in the "as-found" condition as discussed in the Technical
Specification Bases 3/4.9.C. Failure to perform a MPT in the "as found" condition
is a Violation of Technical Specification 4.9.C.5 (50-237;249/97007-05).
The team reviewed, with the assistance of a Region Ill specialist inspector, the
licensee's operability determination (Document ID 97-69) initiated on May 3, 1997,
to document the licensee's technical evaluation of the Unit 3, 250 VDC battery
with regard to the as-left condition following the MPT. The team concluded that
the Unit 3, 250 voe battery was operable based on the minimum effect the actual
pre-test maintenance had on the battery's performance, as demonstrated and
measured during the actual test. In addition, the team concluded the equalizing
charge, by chance, did not elevate the battery voltage above what would be an
acceptable float voltage prior to test performance. Subsequent to the inspection,
Dresden Licensee Event Report 97-005, dated May 16, 1997, was submitted to the
NRC, which documented the licensee's evaluation and corrective action for the
failure to properly perform the MPT.
On April 10, 1997, a scheduled pre-maintenance work package review identified
that DES 8300-20, Step E.3, required the MPT to be conducted in the "as found"
condition. The system engineer (test director and cognizant supervisor for the
31
MPT) was contacted and informed that the planned maintenance activities could
prevent meeting the "as found" prerequisite of DES 8300-20, Step E.3. Believing
the "as found" condition was not a "requirement," the system engineer contacted
corporate engineering for an assessment of the "as found" requirement. Corporate
engineering memorandum DOC No. DG-97-000513, dated April 14, 1997,
recommended that the "as found" requirement be waived. On April 17, 1997, the
system engineer (test director) attached the corporate memorandum to the test
procedure and noted on Attachment G that: "Battery is not being tested in the "as
found" condition as required in prerequisite E.3."
The system engineer, with the concurrence of corporate engineering, revised the
procedure to delete the as found requirement. That procedural revision was made
outside the Dresden station procedural controls and/or processes.
Dresden Station Technical Specification 6.8.A required that written procedures shall
be established, implemented, and maintained covering the applicable procedures
recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Appendix A of Regulatory Guide 1.33,* Revision 2, February 1978, referenced
administrative procedures, procedure adherence and temporary change method, and
procedural review and approval.
Dresden Administrative Procedure (OAP) 09-13, "Procedure Adherence,"
Revision 6, Step F.9.a & .c required the cognizant supervisor to ensure: a) "If the
Procedural Intent will be affected, THEN perform step F.2.a of this procedure," and
c) "Applicable prerequisites are met." Step F:2.a required that the cognizant *
supervisor terminate use of the procedure OR perform a permanent change in
accordance with station procedure and revision processing.
On April 17, 1997, the cognizant supervisor (test director) changed DES 8300-20,
based on a corporate engineering recommendation that the "as found" requirement
be waived. Deleting the "as found" prerequisite was a*n intent change. Failure of
the cognizant supervisor to terminate use of DES 8300-20 OR to perform a
permanent change in accordance with station procedure and revision processing is
a Violation (50-237;249/97007-06).
c.3
Conclusions Unit 3 250 VDC Battery Modified Performance Discharge Test
The licensee's performance of the Unit 3 modified performance discharge test on
the 250 V battery was inadequate in that it failed to comply with plant Technical
Specifications concerning the requirement to be tested in the uas found" condition.
In addition, changes. were made to the battery test procedure which did not receive
the required review by station administrative procedures.
b.4
Observations and Findings on Molded Ca_se Breaker Maintenance
While observing breaker work in the electrical shop, the team discussed the planned
work with electrical maintenance personnel. At the time of the observation, the
maintenance personnel had stopped work on the task and contacted engineering
32
personnel for assistance in correcting an inadequate work package. The work
instructions directed electrical maintenance to reference a separate document to
inspect and test the breaker. The referenced procedure was not correct for the
specific breaker and did not provide correct inspection and testing criteria. The
team observed the initial response to the work instruction error. The maintenance
technician stopped work and contacted engineering for assistance, and the licensee
initiated a PIF to document and resolve the problem.
c.4
Conclusions on Molded Case Breaker Maintenance
The team concluded that maintenance personnel responded appropriately to the
procedural deficiency. However, the incorrect work package instruction
represented an example of poor pre-job preparation.
b.5
Observations and Findings on Troubleshooting of a 125 VDC Ground <Unit 3)
The team performed routine inspection activities of the licensee's followup to a full
negative ground on the Unit 3, 125 VOC system. Portions of the electrical field
work activities were observed and a subsequent review of the work documentation
was also performed.
The electricians involved in the identification of the source of the ground utilized
OAP 15-07, "Electrical/Instrument Maintenance Troubleshooting Procedure (W-1),"
Revision 05. The. team observed electricians in the field attempting to re-land four
wires that had been lifted by a previous work crew. The team observed that the
assigned electricians failed to utilize adequate self check techniques and initially
went to the wrong cabinets in search of the lifted leads. Subsequently, the
licensee initiated a PIF on the inadequate self-check to document immediate and
planned corrective actions.
c.5
Conclusions Troubleshooting of a Ground on the 125 V DC System (Unit 3) *
The team's observations of the troubleshooting of the Unit 3, 125 VOC ground
noted that the assigned electricians initially failed to perform an adequate self-
check.
c.
General Conclusions on Electrical Maintenance Performance
In general, the performance of electrical maintenance activities observed appeared
to be properly planned, performed, and documented. Workers appeared to be
knowledgeable and capable of performing the work activities. The TS battery
surveillance problem appeared to be isolated, but the fundamental problem
regarding procedural controls was significant .
33 '.
MS
Miscellaneous Maintenance Issues
MS.1 Maintenance Backlog
a.
Inspection Scope
The team reviewed the station's backlog of maintenance tasks to evaluate the
licensee's understanding of the cu~rent status. For the purpose of this inspection,
the team utilized the licensee's computerized station backlog data base for action
requests, work requests non-outage, and work requests outage. In addition, a
general review of all maintenance tasks was performed which included a review of
the total station corrective, preventative, modifications, facility, other, and
unknown categories. The computer data base was utilized by the team for
selection of a sample of specific action requests and/or work requests based on
significance, age, and planning status. The review of specific maintenance tasks
was performed by review of station records, interviews of cognizant licensee
personnel (e.g., system engineer), and in some cases through direct field
observations of the maintenance task.
b.
Observations and Findings
b. 1
Action Request Backlog
The Powerblock Backlog for action requests (ARs) dated April 16, 1997, was
utilized for review of the station's AR backlog. That report detailed the current AR
backlog and categorized the 254 open ARs. The AR Powerblock Backlog contained
four categories, which included origination (7), hold awaiting approval (223),
approved (1 ), and minor (23).
The initiating document to perform all work at Dresden was the AR. In general,
only minor maintenance activities in the powerblock could continue to be performed
with only an AR (e.g., change light bulb, paint hand rail, etc.). If more than minor
maintenance was required, a work request was necessary. The AR backlog was
further divided into sub-categories based on outage and non-outage work. The
team reviewed in detail the 220 ARs coded non-outage and on hold awaiting
approval. The team noted that the majority of ARs in the "non-outage on hold
awaiting approval" category (183) had an average age of 11 days. However, a
sub-set of 37 ARs coded as corrective "non-outage on hold awaiting approval" had
an average age of 72 days. Through discussions with c~gnizant station personnel,
the team learned that the corrective ARs coded as non-outage on. hold awaiting
approval were actually approved for work by the station's fix-it-now (FIN) team and
the intent was to capture work when completed, i.e., as the FIN team reported
work complete, the status of the item would be changed to "completed." The
team was able to directly observe the licensee's process through attendance at a
daily action request screening meeting; however, the computer coding for all
ComEd stations showed Dresden was the only ComEd station that was using the
on-hold awaiting approval code to track ARs coded corrective to closure.
34
c.1
The team concluded that the AR backlog was relatively low and only contained
tasks that would not require a station work request to accomplish.
b.2
Work Request Backlog
The Backlog Average Age report dated April 16, 1997, was utilized for a review of
the station's maintenance work request (WR) task backlog. That report detailed the
current WR task backlog and categorized the station's 11,805 maintenance tasks.
The maintenance tasks were categorized into corrective (2743), preventative
(6782), modifications (721), facility (516), other (1042), and unknown (1).
In order to evaluate the validity of the maintenance backlog, the team selected a
representative sample of work request tasks, discuss~d the current status of each
task with cognizant licensee personnel, and in some cases, performed direct field
observations of the deficient condition. Of particular interest were WR tasks
(outage and non-outage) that appeared to be significant, were more than one year
in age, and had not yet been planned.
b.2.1 Non-outage Work Request Tasks
Non-outage WR tasks reviewed included the following:
Task Number
WR 940099081-01
WR 950068772-01
WR 950096403-01
WR 950102600-01
WR 960013596-01
WR 950105270-01
WR 9601168~9-01
WR 960119324-01
WR 970014631-01
WR 970018642-01
MM
WR 940099406-01
WR 950121192-01
WR 960031482-01
WR 960033231-01
WR 960077518-02
Status *
22
22
22
22
22
23
22
22
22
22
22
25
22
22
45
Description
Torus spray electrical breaker trip
Diesel generator control circuit
Inboard MSIV solenoid lights panel
Reactor control panel isolation barrier
Replace Unit 2/3 DG frequency relay
. CRD charging water header gage ruptured
Control room refrigeration pressure gage
Crib house temperature gage broke
Oxygen concentration meter broke
Drywall radiation monitor trip
CRD hanger rod tied off to station
Inlet valve missing flange bolts
CCSW [containment cooling service water] pipe
support spring can adjustment
SBLC [standby liquid control] outboard drain
valve stuck open
Control rod drive water pump
- Task status codes referenced in the above table were defined as:
35
Status 22 = Investigation not required (task originated);
Status 25 = planning complete; and
Status 45 = task ready.
b.2.2 Non-outage work request task soecific observations:
Work Request Task 940099081-01 was initiated on December 2, 1994, to adjust
breaker trip settings on Low Pressure Coolant Injection (LPCI) Valve 2-1 501-188.
In response to concerns about spurious reverse-current tripping of motor operated
valves, described in Licensee Event Report 50/237-94-030 dated December 23,
1994, a number of motor operated valves were initially identified as potentially
having motor trip settings that were too low. Although initially prioritized as a "81"
(urgent-work start within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />), the task had since been down-graded to a "C"
priority (routine work). Through discussions with cognizant licensee personnel and
review of historical inspection records, the team learned that the LPCI 2-1501-188
valve's motor had sufficient margin to preclude spurious trips and the urgent
classification was no longer required. The as-left breaker trip values for MOV 2-
1501-188, when last tested on October 1, 1990, were adequate to eliminate this
valve from the original suspect population and the current work task was no longer
needed. The team identified that another open work task, not in the team's original
inspection sample (WR Task 94009908201 for Reactor Water Cleanup Valve 2-
1201-1), was similar in that the original task to adjust motor trip settings was no
longer necessary. The team noted that these two work tasks were confusing the
known backlog of non-outage work .
Work Request Task 950096403-01 was initiated on September 30, 1995, to
address a foreign material entry point for an electrical panel for main steam isolation
valve (MSIV) pilot indicating lights. After direct field observation, accompanied by
cognizant licensee personnel, the team observed that the existing condition was not
an immediate concern to the integrity of the electric panel and was properly coded
for routine non-outage work.
Work Request Task 970014631-01 was initiated February 6, 1997, to address a
broken Unit 2 Drywell local oxygen concentration meter. The team identified that
the same meter was the subject of WR 930053045, written in 1993, but that WR
was closed out, without repair, and the licensee was tracking the known deficiency
against open Engineering Request 9503291. The 1997 WR was written since no
immediate information was present in the field to identify that the engineering
request already existed. The licensee annotated the existing 1997 WR to reflect it
would remain open until the engineering request was worked, and a "two-part" tag
was to be hung in the field on the oxygen meter to identify that the deficiency was
a known problem.
Two non-outage WR tasks were identified by the team as being coded incorrectly.
Specifically, WR Task 970037904-01 and 950118049-02 involved work in the
Drywell, but both tasks were coded as non-outage. The Drywell was not normally
accessible during plant operations and the tasks should have been coded to be
performed during an outage .
36
c.2
b.3
Work Request Task 950102600-01 was initiated October 20, 1995, to repair an
isolation barrier for a terminal block inside a reactor control panel. The team
directly observed the deficient condition, and the licensee's classification of non-
outage routine work was considered reasonable.
The team concluded that the non-outage work request backlog contained tasks that
were appropriate to be completed while the units were either operating.
Outage Work Request Tasks
In addition to the non-outage tasks above, the team selected a representative
sample of outage tasks scheduled to work in future refueling outages. The
inspection sample included tasks scheduled for the next Unit 2 or Unit 3 refuel
outage, i.e., D3R15 or D2R15. The non-outage work request tasks reviewed
included the following:
Task Number
Status
.CE/CM/EM
WR 950064036-01
25
thru
WR 950064105-02
WR 950041246-01
22
WR 950066503-01
45
WR 970019996-01
22
WR 950066654-01
45
MM
WR 890063385-01
22
WR 910053212-01
25
WR 930049144-01
25
WR 930053086-01
22
. WR 940098057-01
45
Description
Drywall fan blade adjustment to rated flow
(note: the Drywall work involved 13 separate
work request tasks that were initiated to resolve
concerns with the Drywall ventilation system)
Cracked end bell on HPCI aux oil pump
Replace 3C drywall cooler motor and fan
Hydraulic Control Unit (HCU) leaks
Note: there were a number ( > 100) of small
(single drop) body to bonnet leaks on small
.
manual valves in the HCU system.* The known
Unit 3 leaks were captured on 4 7-work request
tasks.
2A MG set oil cooler outlet valve leak
Adjust oil pressure to main bearing
Turbine building supply fan bearing
Unit 3 HVAC inspection doors
Adjust spring can on
37
b.3. 1 Outage work request task specific observations:
The station's computer listing of all 11,805 station maintenance tasks included one
item that was categorized as *unknown," and at the time of the inspection that
item was 287 days old. The unknown item was identified to be a preventative
maintenance task captured in WR Task 960023216-02. That task was intended to
assure the proper 0-rings were used as replacements during an EO surveillance on a
low pressure coolant injection (LPCI) motor oil sightglass inspection. The unknown
classification was due to a coding error.
Work Request Task 950064036-01 and associated tasks were initiated in July
1995 to adjust fan blades and restore "rated flow* to the Unit 3 Drywall coolers.
These tasks were not being worked during the current Unit 3 refuel outage
(D3R14), but were deferred to the next Unit 3 refuel outage (D3R15). During the
current refuel outage, additional ventilation flow information (e.g., cooler fan motor
amperage and system flow rates) was being obtained to better assess the need for
fan blade adjustments. Through discussions with the system engineer, the team
learned that adequate Drywall flow existed to meet operating parameters, and the
licensee's decision to defer any field work pending the results of further testing was
reasonable.
Work Request Task 950066503-01 initiated in July 1995 was originally intended to
replace Drywall cooler fan motor 3C during the current Unit 3 refuel outage
(D3R14). However, due to a parts availability problem, the task was deferred until
the next refuel outage (D3R15). Through discussions with the system engineer,
the team learned that the subject task was part of a planned system predictive
maintenance effort to replace all Drywell cooler fan motors. The team noted that
during the current refuel outage (D3R 14), Drywall cooler fan motor 3A was being
replaced under WR Task 950066504-01. Since the existing 3C Drywall cooler fan
motor was still performing well, the team concluded the licensee's decision to defer
the subject work to the next refuel outage was reasonable.
Work Request Task 950066654-01 and other associated tasks were initiated
between August 1995 and October 1996 to repair leaks on small manual valves on
the control rod drive system's hydraulic control units (HCUs). As discussed in
licensee electronic memorandum, "Paul Chanell to Frank Spangenberg," dated
April 24, 1997, the decision to defer a number of tasks on small HCU manual
valves was based on a root cause investigation plan that was being implemented by
station engineering. The licensee was in the process of inspecting and replacing
25 of the subject valves in an attempt to identify the root cause for continued
problems with the subject manual valves. Initially, all leaking valves were proposed
to be repaired; however, the licensee deferred a number of valve repairs pending
the root cause determination. The licensee's decision to defer repair on some
valves was based on the criteria that the valve was outside the system hydro
boundary, and a catch basin or funnel was not required to capture the small amount
- of leakage. .
38
c.3
The team concluded the outage work request tasks were appropriately assigned to
work during a unit outage. In addition, the licensee provided reasonable
explanations for work tasks that deferred to future outages.
b.4
Non-outage Corrective Tasks Backlog Assessment
Over the last several years, the licensee has focused attention on the backlog of
"non-outage work request" as a measure of overall station performance in the area
of corrective maintenance. At the time of this inspection, the non-outage WRs had
been further refined to define the specific number of "tasks" for each WR. This
definition was used at all six Corned stations as a way of standardizing station
backlogs.
In addition to the sample inspection of specific non-outage work request tasks, the
team reviewed the existing non-outage backlog to determine distribution of the
backlog with respect to age and the station work group assigned responsibility for
closure. The following table is representative of the non-outage work request task
backlog for the powerblock that existed at the time of the inspection.
yROUP
1997
1996
1995
IM
98
25
5
204
114
35
MM
208
163
33
FN
70
7
2
4
1
1
HVA
33
6
3
VM
29
134
44
MISC
31
15
3
TOTAL
677
465
126
TABLE NOTES
- = 1993 or earlier for this column;
IM = instrument mechanics;
EM = electrical maintenance;
MM = mechanical maintenance;
FN = fix it now team;
1994
1
23
23
N/A
N/A
4
18
4
73
CFM = consolidated facility maintenance;
1993*
TOTAL
0
129
14
390
14
441
N/A
79
N/A
6
2
48
9
234
0
53
39
. 1380
=
HVA = heating ventilation and air conditioning maintenance team;
VM = valve maintenance team;
MISC = miscellaneous category with ten different sub-groups; and
N/A = not applicable .
39
The team reviewed the above backlog to evaluate the licensee's awareness of the
station's backlog of WR tasks and how those tasks were prioritized. The following
observations were made:
In general, the age of the existing backlog was skewed in a direction
indicating progress was being made at working off older items. The majority
(83 percent) of the non-outage backlog work request tasks were initiated in
1997 or 1996.
The licensee was emphasizing the oldest work request tasks through a
"Top 50" list that was intended to focus the responsible work group
attention. In addition, the ten oldest corrective tickets were specifically *
highlighted during the Plan of the Day meeting which was chaired by senior
station management.
The Plan of the Day meeting conducted a detailed review of the powerblock
backlog. The focus of that review, which included open WR and AR tasks,
was the station's weekly progress in completing scheduled work.
c.4
The licensee's knowledge of the current maintenance backlog was good. In
general, the maintenance backlog was appropriately coded so individuals
responsible for work prioritization had a sound data base. Some confusion in the
data base existed due to incorrectly coded work requests, and work tasks included
in the data base but actual field work was no longer required. The backlog of non-
outage work request tasks was skewed in a direction indicating positive progress
was being made at reducing the oldest backlog items and focusing attention on
more recent equipment deficiencies.
IV. Radiation Protection
R 1
Radiological Protection and Chemistry Controls
R 1 . 1 Actions to Control Licensed Radioactive Material within the Radiologically Protected
Area
a.
Inspection Scope (837501
The team reviewed the corrective actions specified in .licensee letter to the NRC
dated February 26, 1997, to prevent recurrence of the loss of control of licensed
radioactive material (RAM), in the form of contaminated articles, outside the
radiologically protected*area (RPA). The review consisted of interviews with plant
staff, observations of work in progress, walkdowns of the site, and review of
documentation .
40
,
b.
Observations and Findings
The team reviewed the survey log for dumpsters leaving the protected area from
January 24 through April 22, 1997, and noted that these surveys were conducted
, regularly with new meters designed to detect low levels of radioactivity. Radiation
protection technicians (RPTs) stated that only properly trained individuals were
allowed to conduct these surveys. The team observed that radworkers obtained
authorization from a radiation protection supervisor (RPS) before entering the RPA
with various work materials, and that the greeters quizzed the workers regarding
the need and authorization for this material. In addition, a review of the radiation
protection (RP) rover log revealed that rovers aided in the survey of items for
clearance from the RPA and raised housekeeping issues that had the potential to
result in the loss of control of contaminated materials.
The team reviewed the new stanchion control policy (Policy #71 ) which stated that
only yellow stanchions shall be used in the RPAs and green stanchions shall be
used in all others areas. The policy also stated that temporary satellite RPAs
(SRPAs) with smearable contamination items shall be surrounded by yellow
stanchions with a buffer zone of green stanchions surrounding the yellow
stanchions. During site walkdowns, the team noted that the stanchion policy was
well implemented. The team also observed the presence of a barrier on the second
floor of the Unit 2 side of the turbine building erected to separate the RPA and non-
RPA portions of the turbine building. Notes from the presentation given by the
radiation protection manager (RPM) at a site-wide meeting held on January 1 7,
1997, regarding the past problems with control of RAMs ~nd interviews with site
personnel indicated that control of RAM was effectively communicated.
The team interviewed RPS staff regarding a benchmarking visit to another nuclear
power plant. As a result of this visit, the RPS staff developed a satellite RPA
reduction plan to eliminate and consolidate the current 88 SRPAs into 30 SRPAs
after the Unit 3 outage. The team conducted an SRPA walkdown, interviewed the
lead RPS, and reviewed the SRPA reduction plan and noted that these actions
appeared adequate to address the recurrent problem of loss of control. The RP
staff also planned to establish a hot tool facility for the storage, use, and
decontamination of tools used in the RPA.
c.
Conclusion
The team concluded that some of the corrective actions to control licensed
radioactive material within site RPAs had been adequately implemented. Those
actions scheduled for implementation after the current Unit 3 outage appeared
sufficient to improve licensee performance in this area .
41
R 1.2 Actions to Effectively Control Access to High Radiation Areas
a.
Inspection Scope <837501
The team reviewed the status of corrective actions specified in licensee letter to the
NRC dated February 26, 1997, to prevent the recurrence of problems associated
with high radiation area (HRA) access. The review consisted of interviews with
plant staff, walkdowns within the RPA, and review of documentation.
b.
Observation and Findings
The team observed that the HRA keys were controlled and inventoried by RP staff.
Access to the HRA keys was limited to one RPT at the RP access control desk and
the inventory log was updated daily. Swing gates with proper postings were
located at the entrances to high radiatiOn areas throughout the plant, although the
alarms had not been installed. The team noted that greeters were not quizzing
radworkers about HRA controls and radworker responsibility. RPS staff stated that
greeter practice regarding HRA issues would be reviewed.
A RP staff survey of the HRA and locked HRA (LHRA) doors revealed 32 material
deficiencies. The lead technical health physicist was given the responsibility to
track and disposition the identified deficiencies. At the time of this inspection, six
- HRAs were surveyed and downgraded to radiation areas, four areas were
downgraded from LHRAs to HRAs, and 26 of the 32 action requests written to
repair LHRA and HRA access points were complete. The team verified that the 2/3
maximum recycle demi.neralizer room LHRA door was locked.
Interviews with staff and a review of training notes from a presentation given by
the RPM to plant radworkers indicated that the workers were aware of
responsibilities and management expectations regarding work in HRAs. Regulatory,
TS, and procedural requirements were also communicated to the station
radworkers. RP and training staff stated that lesson plans addressing HRA issues
were being developed for integration into the operations, engineering, and
maintenance continuing training cycle.
c.
Conclusion
The team concluded that many of the.corrective actions had been implemented.
However, some training and repair issues remained incomplete. In addition, the
action to have greeters address HRA issues was not communicated to the greeters,
and was not being conducted.
R 1.3 Review of Refueling Outage Performance
a.
Inspection Scope
The team reviewed the licensee's radiological controls, dose and/or as low as
reasonably achievable (ALARA) effort, and work practices for the D3R 14 refueling
42
outage. The inspection consisted primarily of in-plant observations, attendance at
pre-job meetings, review of records (ALARA plans, radiation work permits (RWPs),
work packages, etc.), and discussions with workers and members of the work
control groups. The following radiologically significant jobs were inspected:
Reactor Water Cleanup (RWCU) Pipe Replacement
RWCU Removed Pipe and Heat Exchanger Shipping Activities
Removal of Waste Activities Associated with the RWCU
Refuel Floor Work Activities
Aspects of the Control Rod Drive (CRD) Removal Activities
Valve Work Activities
Drywall Work Activities
b.
Observations and Findings
As of May 2, 1997, the licensee had accrued about 118 rem (the projected goal for *
this period was 180 rem) with about fifty five percent of the scheduled work
completed. At that point, the overall outage dose was expected to be lower than
the original goal of about 300 rem (at the exit meeting on May 12, the licensee
informed the team that the goal for the Unit 3 outage had been reduced to
245 rem). To date, considerable work which had been included in the dose goal did
not need to be accomplished because many of the plant systems passed required
local leak rate tests (LLRTs). Added work scope, rework, and emergent work
accounted for about 40 rem, most of which was due to added scope. The outage
work scope growth was primarily due to work that was found to be required after
post shut down surveillances were performed.
ALARA controls such as mockup training, shielding, RWCU chemical
decontamination efforts, (the average decontamination factor was about 15), and
use of remote cameras and teledosimetry were implemented. Major outage
activities were assigned persons to be responsible for developing and implementing
the ALARA plans and ensuring radiological controls were used. Oversight by
radiation protection personnel and sufficient coordination between working groups
was observed. For those pre-job meetings attended, roles and responsibilities of
individuals were clearly discussed, and special instructions were prepared for those
jobs observed by the team. The team also observed the radiological controls
established for several jobs including the Unit 3 drywall, RWCU, and refuel floor
work activities. In addition, conservative radiological controls had been planned for
and were implemented for all work where there were indications of alpha
radioactivity.
43
c .
Although the radiation protection staff was observed to be aggressive in challenging
workers concerning loitering, knowledge of RWPs, general dose rates, and
monitoring requirements, the team observed some poor radworker practices that
could be prevented by closer oversight:
During the handling and loading of removed RWCU piping into transportation
bins, on two occasions, workers appeared to be loitering in general radiation
fields of 10 to 20 mrem per hour. Other workers were noted to be loitering
in radiation fields between the Unit 2 and Unit 3 door on the main floor in
radiation fields of about 6 mrem/hr.
Workers were instructed to perform a hand held frisk in a shielded booth* *
close to the RWCU work exit area, and then perform a whole body frisk
(PCM-18) at a lower elevation. On one occasion, the team observed four
workers exit the RWCU area, perform the hand held frisk, but only two of
the four performed the expected whole body frisk. On another occasion, the
team observed four workers exit the RWCU area, and neither a hand held
frisk or whole body frisk was performed.
These observations were discussed with the licensee, and RWCU work was
stopped until all persons associated with the project were instructed in licensee
expectations of worker performance.
Conclusions
The team concluded that, in general, radiological controls, ALARA initiatives, and
job planning were effectively implemented which contributed to the lower than
projected dose for the outage. Although some poor practices were observed,
overall, there was good effort to prevent loitering and unnecessary crew size.
R 1.4. Radiation Worker Practices
a.
Inspection Scope
The team observed general radiation work practices including personal monitoring,
use of protective clothing, dosimetry placement (thermolumenescent dosimetry
(TLDs) and electronic dosimeters (EDs)), working conditions, understanding general
and specific area dose rates and RWP requirements, and station housekeeping.
b.
Observations and Findings
The team observed. that the normal station practice was to put both the electronic
dosimeter (ED) and the theroluminescent dosimeter (TLD) in the same pocket with
both covered by the fabric of the PC. The team observed, on at least six
occasions, radiation workers placing their TLD or ED under protective clothing (PC),
and on two occasions the workers were radiation protection technicians .
44
...
Dresden Technical Specification 6.8.A required, in part, that written procedures
shall be implemented covering the activities referenced in Appendix A of Regulatory
Guide (RG) 1.33, "Quality Assurance Program Requirements (Operation),"
Revision 2, February 1978. Administrative and maintenance procedures were
referenced in RG 1 .33.
Dresden Administrative Procedure (OAP) 12-35, "Donning and Removal of Routinely
Required Radiological Protective Clothing Alli! PC Guidelines," Revision 4, Step F.1.j
required (unless otherwise directed by RWP QB Radiation Protection), that TLDs be
clipped to the PC pocket with the beta window showing and not covered by fabric,
and EDs were to be placed in the pocket. Failure to follow OAP 1 2-35 with regard
to the use of TLDs and EDs is another example of a Violation of TS 6.8.A
(50-237;249/97007-03d).
During a tour *of the sub-basement in the Unit 3 drywall, ladders and other debris
were observed almost blocking the entrance into the under-vessel area. The Unit 3
drywall coordinator removed the debris during the tour.
The team identified that packages of new piping insulation were staged in the
corner of the Unit 3 west LPCI corner room to support ongoing work. The
packages were radioactively clean and roped off in a noncontaminated area.
However a posted, radioactively contaminated trough ran along the base of the
floor and some piping insulation packages were laying across the contamination
boundary and in the contaminated trough. A radiation protection technician (RPT)
subsequently posted and controlled the area and as contaminated.
c.
Conclusions
The team concluded that most plant workers were adhering to acceptable
rad worker practices. However, the team concluded there were some instances of
poor procedural adherence or poor radworker practices.
V. Management Meetings
X 1
Exit Meeting Summary
The team discussed the progress of the inspection with licensee representatives on
\\ a daily basis and discussed inspection progress to members of licensee
management on April 25, 1997. A public exit meeting was held .on May 12, 1997.
In all cases, the _licensee acknowledged the findings presented.
45
PARTIAL LIST OF PERSONS CONTACTED
Licensee
- S. Perry, Vice President, BWR Operations
- J. Heffley, Units 2 and 3 Station Manager
- F. Spangenburg, Regulatory Assurance Manager
- P. Swafford, Unit 2/3 Maintenance Superintendent
- R. Freeman, Site Engineering Manager
- D. Winchester, Safety Quality Verification Director
- T. Foster, Work Control and Outage Manager
- c. Howland, Radiation Protection Manager
- o. Willis, EMO Super"intendent
- M. Milly, EMO General Supervisor
- s. Stiles, IMO Superintendent
M. Pacilio, Outage Manager
S. Barrett, Operations Manager
- R. Schultz,
- c. Settles, State of Illinois, Resident Inspector
- A. B. Beach, Regional Administrator, Riii
- R. J. Caniano, Acting Director, Division of Nuclear Material Safety, Riii
- G. E. Grant, Director, Division of Reactor Projects, Riii
- J. A. Grobe, Acting Director Division of Reactor Safety, Riii
- W. J. Kropp, Branch Chief, Division of Reactor Projects, Riii
- P. L. Hiland, Branch Chief, Division of Nuclear Material Safety, Riii
- K. R. Riemer, Senior Resident Inspector, Riii
- C. E. Brown, Resident Inspector, Riii
- o. E. Roth, Resident Inspector, Riii
- R. A. Capra, Project Director, Division of Reactor Projects, NRR
- Denotes those attending the May 12, 1997, exit meeting.
p 62707
LIST OF INSPECTION PROCEDURES USED
Operational .Safety Verification
Surveillance Testing
Maintenance Observations
Instrument Maintenance
Electrical Maintenance
Monthly Maintenance Observation
46
"
LIST OF ITEMS OPENED
Opened
50-237;249/97007-01
Failure to Follow Administrative and Test Procedures
During the Conduct of Instrument Maintenance
50-237;249/97007-02
Failure to Follow Instrument Surveillance Procedures
50-237;249/97007-03
Failure to Follow Administrative Procedures for FME
50-231;249/97007-04
Failure to Follow Mechanical Maintenance Procedures
During Welding
50-237;249/97007-05
Failure to Test 250 VDC Battery in As Found Condition
50-237;249/97007-06
Failure to Follow Administrative Controls for Procedural
Changes
A LARA
ccsw
CFR
Com Ed
cs
- CST
D3R14
OAP
DCN
DDS
DES
DIP
DIS
DTI
ow
E~D
EWCS
LIST OF ACRONYMS USED
As Low As is Reasonably Achievable
Action Request
American Society of Mechanical Engineers
Analog Trip System
Anticipated Transient Without Scram
Continuous Air Monitor
Containment Cooling Service Water
. Code of Federal Regulations
Commonwealth Edison Company
Control Rod Drive
Control Systems Technician
Dresden Unit 3 Refueling Outage 14
Dresden Administrative Procedure
Design Change Notice
Dresden Electrical Surveillance
Dresden Electrical Surveillance
Dresden Instrument Procedure
Dresden Instrument Surveillance
Desk Top Instructions
Drywell
Electronic Dosimeter.
Electrical Maintenance
Electrical Maintenance Department
Environmental . Qualification
Electronic Work Control System
47
...
IEEE
IM
IMO
kV
MMD
MPT
NRC
NSWP
ace
oos
RPA
RPT/ARI
S&LP
SBLC
SRPA
STU
TS
voe
VPOP
Fix it Now Team
Final Safety Analysis Report
Hydraulic Control Unit
High Pressure Coolant Injection
Instrument Controls
Institute of Electronic and Electrical Engineers
Instrument Mechanic
Instrument Maintenance Department
Kilovolts 4kV . = 4160 volt
Local Leak Rate Test
Low Pressure Coolant Injection .
Local Power Range Monitor
Mechanical Maintenance Department
Maintenance and Test Equipment
Motor Operated Valve
Modified Performance Test
Master Trip Unit
Nuclear Regulatory Commission
Nuclear Station Work Procedure
Outage Control Center
Out-of-Service
Public Document Room
Problem Identification Form
Plant Onsite Review Committee
Regulatory Guide
Radiation Protection
Radiologically Protected Area
Radiation Protection Supervisor
Radiation Protection Technician
Recirculation Pump Trip/Alternate Rod Insertion
Radiation Work Permit
Safety & Loss Prevention
Satellite Radiologically Protected Area
Source Range Monitor
Slave Trip Unit
Thermoluminescent Dosimeter
Technical Specifications
Volts Direct Current
Valve Packing Optimization Program
Work Execution Center
OAP 01-04 .
OAP 02-31
OAP 03-05
OAP 03-23
OAP 04-01
OAP 04-02
OAP 04-20
OAP 07-14
OAP 07-27
OAP 12-35
OAP 15-01
OAP 15-06
OAP 15-10
OAP 18-04
OAP 18-05
OAP 18-06
OAP 18-07
OAP 18-09
NSWP-WM-08
NSWP-WM-09
DIP 0700-08
DIS 0700-09
LIST OF DOCUMENTS REVIEWED
Contractor Controls
Electronic Work Control System (EWCS) Administration
Out of Service Program
Foreign Material Exclusion Program
Maintenance Department Organization
Dresden Preventive Maintenance Program Control
Calibration Program for M & TE/Standards
Operations Key Control
Independent verifications
Donning and Removal of Routinely Required Radiological Protective
Clothing and Protective Clothing Guidelines
Initiating and Processing a Work Request
Preparation, Approval, and Control of Work Packages and Work
Requests
Post Maintenance Testing Program
Management of Planned Outages
Shutdown Risk Assessment and Management
Long Range Planning
Implementation of the Fix it Now (FIN) Process
Work Activity Screening
Action Request Screening Process
Maintenance Work Scheduling Process Week E-5 to E + 1
SRM, IRM, and TIP Detector Resistance & Breakdown Voltage Checks
Preventative Maintenance and Calibration of IRM, SRM, RBM, LPRM
and APRM power supplies
49
..
DIS 0700-30
DIS 1500-14
DIS 2400-01
DES 8300-20
SRM/IRM Cable Routing and Detector Acceptance Test
LPCI System Discharge Header Flow Channel Calibration and Channel
Functional Test and Transmitter EO Maintenance Inspection
Post LOCA Containment H2/02 Analysis Functional/Calibration Test
Unit 3 250 vdc Station Battery Modified Performance Test
WR 950065509-01 Valve Flow Scans
WR 950070276-01 Main Condenser Expansion Boot Repair
WR 960096685-02 Welding in Torus
WR 960034393-01 H2/02 Monitor Repairs
WR 970002945-01 LPCI Master Trip Unit Calibration
WR 970032719-01 Calibration of H2/02 Monitors
WR 970042425-01 SRM Short Period Oscillations
WR 940097988-08 Unit 3 Replace Yarway Reactor Water Valve Switch
WR 950060521-01 D3 RFL EMO EQ GE 3A LPCI PMP MOTOR SURVEILLANCE
WR 960087265-01 2A MG Set Lube Oil Brg Oil Low Press Switch Vertical Mounting
Position and Calibration
WR 950062900-02 38 LPCI Cnmt Clg HX SW Outlet MOV Refurbishment and Calibration
WR 970001564-01 2A Off Gas Condenser Normal Level Control Malfunction
WR 960096144-01 2A Reactor Recirc MG Set Clamp MG Set Scoop Tube and Perform
DIS 0202-04
WR 970043047-01 Troubleshoot and Repair Unit 2 DW CAM Pegged Low
WR 970005193-01 D1, 2, 3, and 2/3 San PM River Temp Recorder Cal.
WR 960105540-01 U2 HPCI P*ump Suction from Condensate Storage Tank Check Valve
Disassembly and Inspection
WR 970041990-01 U2/3 Air Filtration Unit 4 Inch Charcoal Filter Halide Testing
WR 950060862-01 Bus 34 - Clean, Inspect Bus Bars, Wiring, Supports,
Insulation
50
.0
WR 950065566-01 U3 Main Steam Line C High Flow Isolation Non-TS
Surveillances
WR 960099060-01 Install Terminal Screws to ATWS Analog Trip System
Cabinet A
WR 970044365-01 Reinforce U2 Flued Head Anchor X-1168
Instrument Maintenance Task to Training Matrix
Instrument Maintenance Qualification Card 102
Instrument Maintenance Qualification Card 103
Unit 2, DIS 1600-03, Revision 07, "Torus to Reactor Building. Vacuum Relief Valves Trip
Unit Calibration" dated April 4, 1997
Unit 2, DIS 2400-02, Revision 10, "Post-LO CA Containment Hydrogen and Oxygen
Analyzer 18 Month Calibration and Maintenance Inspection" dated March 20, 1997
Unit 2/3, DIS 5700-04, Revision 0, "Reactor Building Vent Stack Flow Monitor Functional
Test" dated Aug 08, 1995
Unit 2, D'S 0263-07, Revision 08, "Unit 2 ATWS RPT/ARI and ECCS Level Transmitters
Channel Calibration Test and EQ Maintenance
Inspection" dated April 15, 1997
-
Unit 2, DIS 0250-01, Revision 14, "Main Steam Line High Flow Isolation Switch
Calibration" dated October 29, 1996
Unit 3, DIS 9900-01, Revision 07, "Computer Controlled Analysis Input Instrument
Calibration" dated April 17, 1997
Unit 2, DIS 0700-10, Revision 06, "Source Range Monitor (SRM) Rod Block Calibration"
dated January 31, 1997
Unit 3, DIS 5600-05, Revision 10, "Turbine Trips Functional Test (Not Tested in Another
Procedure)" dated February 14, 1996
Unit 2, DIS 2300-08, Revision 13, "Units 2/3 Contaminated Condensate Storage Tank and
Unit 2 Torus Level Switches Functional Test" dated March 6, 1997
Unit 2, DIS 0202-04, Revision 01, "Setting Recirculation Pump MG Set Scoop Tube
Control Rod Actuator Assembly Upper Mechanical and Electrical Stop" dated July 12,
1996
Unit 2, DIS 1700-17, Revision 05, "NMC Drywall Continuous Air Monitor Preventive
Maintenance and Calibration" dated December 18, 1996
51
Unit 2, DIS 1400-04, Revision 08, "Emergency Core Cooling System Fill System Alarm
Pressure Switches" dated February 04, 1997
Unit 2, DIS 0287-01, Revision 07, "Automatic Depressurization System CS and LPCI
Pumps Discharge Pressure - High (Permissive) Channel Calibration and Channel Functional
Test" dated April 07, 1997
Unit 2, DIS 1600-04~ Revision 14, "ECCS Drywell Pressure Switches Channel Calibration
and Channel Functional Test" dated March 21, 1997
Unit 3, DIP 0700-06, Revision 03, "LPRM Pre-Installation Insulation Resistance and
Breakdown Voltage Acceptance Checks" dated April 10, 1997
Unit 2, DIS 1600-10, Revision 16, "Drywall and Torus Pressure Instrumentation Channel
Calibration and EO Surveillance for Age Related Degradation" dated March 20, 1997
52