ML20136C405
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| ML20136C405 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 11/04/1985 |
| From: | Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20136C327 | List: |
| References | |
| 50-289-85-24, NUDOCS 8511210083 | |
| Download: ML20136C405 (30) | |
See also: IR 05000289/1985024
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-289/85-24
Docket No. 50-289
License No. DPR-50 Priority -- Category C
Licensee: GPU Nuclear Corporation
Post Office Box 480
Middletown, Pennsylvania 17057
Facility At: Three Mile Island Nuclear Station, Unit 1
Inspection At: Middletown, Pennsylvania
Inspection Conducted: October 11-18, 1985
Inspectors: W. Baunack, Project Engineer, Region I
N. Blumberg, Lead Reactor Engineer, Region I
*J. Cummins, Senior Resident Inspector (Wolf Creek),
Region IV
N. Dudley, Lead Reactor Engineer (Examiner), Region I
*D. Falconer .?r., Lead Reactor Engineer, Region II
D. Haverkamp, Technical Assistant for THI-1 Restart,
Region I
W. Johnson, Senior Resident Inspector (Arkansas),
Region IV
T. Peebles, Senior Resident Inspector (Turkey Point)
Region II
R. Urban, Reactor 'gineer, Region I
D. Vito, Senior Er srgency Specialist, Region I
P. Wen, Reactor Engineer, Reglon I
J. White, Senior Radiation Specialist, Region I
F. Young, Resident Inspector (TMI-1), Region I
Contractor Personnel: B. Gore, Research Scientist, Battelle PNL
J. Huenefeld, Research Engineer, Battelle PNL
* Participation was limited, generally, to site
familiarization training and facility orientation.
Approved By: Id
R. Conte, TMI-1 Restart Manager
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Date
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TMI-1 Restart Staff
Division of Reactor Projects
8511210083 851107
PDR ADOCK 05000289
G PDR
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Inspection Summary:
Routine and special (NRC shift coverage) safety inspection (369 hours) of power
operations focusing on operator and management performance, related startup
testing / operations, decay heat removal system operational verification, licensed
operator requalification program, and gaseous radioactive releases.
Inspection Results:
Operators continued to demonstrate their detailed knowledge of plant design as
.well as their ability to safely operate the facility, especially in the manual
control mode of integrated control system operation. The level of knowledge of
the auxiliary operators was commensurate _with their duties. Maintenance depart-
ment personnel, especially instrument and control technicians, worked well with
control room operators in keeping them informed of their troubleshooting efforts.
Overall, procedures were adequate to support operations and were properly imple-
mented.
Major safety-related equipment remained in service except when surveillance
testing or preventive / corrective maintenance.was conducted. A secondary plant
drain line problem impacted the progress of the test program because of recur-
reat weld cracking due to fatigue failure. Observations were made of worker
actions in building spaces that had the potential to cause unnecessary transients
and/or challenges to safety systems and operators.
The testing program was interrupted slightly due to the secondary plant drain
line problems. Test procedures were properly implemented and, in general, data
were in accordance with the test acceptance criteria. Test briefings continued
to be used routinely.
The operating procedure for the decay heat removal system was adequate for safe
1 operation of the system and it assured that the system was properly lined up
for standby status. The licensee's requalification program is well organized
and documented and conforms to regulatory requirements. The licensee is appro-
priately quantifying non-routine gaseous releases from the facility during
operations. The licensee also provided an interim resolution to our previous
inspection finding on the emergency feedwater system safety valves.
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DETAILS
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1. Introduction and Overview
1.1 General
At the beginning of this inspection period on October 11, 1985, the j
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TMI-1 Restart Staff was providing around-the-clock coverage to assess
- restart operating activities. The plant was then at 15% of rated
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power at normal operating conditions. This continuous observation of
1 plant activities was maintained by inspectors from Regions I, II, and
IV and by reactor operator examiners from Battelle Pacific Northwest
Laboratories, an NRC contractor. Also, Region I inspectors continued
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daily coverage of testing activities. Additional Region I personnel
were on site during portions of the period to augment the resident
inspection staff.
1.2 Facility Restart Operations
, During the period of October 11-18, 1985, the significant TMI-1
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restart operational milestones included (a) completing main turbine
generator testing and electric power generation at the 15% and 25%
testing-plateaus and (2) initial main turbine generator testing at
j the 40% plateau. The chronological summary of plant operations
during this period is presented below.
, Date Time Operational Highlight or Milestone "
,
10/11/85 7:00 a.m. Reactor at 15% of rated power,
reactor coolant average temperature at
567 F and pressure at 2155 psig
10/12/85 2:28 a.m. Conducted overspeed trip test of main
turbine generator
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6:00 a.m. Turbine generator on line
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7:30 a.m. Increased power to 28%
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10/13/85 5:51 a.m. Commenced power reduct un to repair
leak on main steam drain line
6:00 a.m. Turbine generator off line
5:02 p.m. Repairs to main steam drain line
completed and turbine generator on line
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Date Time Operational Highlight or Milestone
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10/14/85 1:00 a.m. Increased power to 29%
1:50 a.m. Commenced power reduction to repair
leak on main steam drain line
. 2:02 a.m. Turbine generator off line ,
9:44 p.m. Repairs to main steam drain line
completed and turbine generator on line
10:55 p.m. Increased power to 27.8%
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10/15/85 10:15 a.m. Commenced increasing power to 40%
11:08 a.m. Reactor power at 40%
- 10/16/85 9
- 30 a.m. Commenced power reduction to repair
, leak on main steam drain line [ 10:07 a.m. Turbine generator off line
8:38 p.m. Repairs to main steam drain line
completed and turbine generator on line
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- 11 p.m. Increased power to 41.5%
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10/17/85 1:15 a.m. Commenced power reduction to repair
- leak on main steam drain line
1:53 a.m. Turbine generator off line
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10/18/85 7:00 a.m. Reactor at 7% of rated power, steaming
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the secondary plant to the main
condenser using the turbine bypass
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valves.
1.3 Operational Events
Recurring problems with weld failures-in two drain lines from the
turbine control valve headers interrupted the startup testing program.
Also, early during the period, there was a power escalation delay due
to inability of one of the integrated control system (ICS) controllers
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to satisfactorily function in the automatic mode. There were no other
events during this period that were considered either operationally
significant or matters of special interest to the TMI-1 Restart Staff.
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The turbine control valve drain line weld failures did not adversely
impact the safe operation of the facility. Nevertheless, the
licensee's test program was delayed several days due to the
recurring weld failures and these failures resulted in considerable
public interest. Therefore, the operating history and sequence of
recent operating problems related to these drain lines is described
in this section.
The piping between the turbine control valves and the high pressure
turbine contains moisture drain lines which are one-inch in
diameter. Two of these drain lines had been installed with a
strainer and an orifice at the time of initial construction of the
facility in the early 1970's. The other two drain lines consisted
of straight pipe and contained no such strainer or orifice.
In 1983 General Electric recommended changing the method of
admitting steam to the high pressure end of the turbine. This
operational change involved some modifications to the turbine
controls and the removal of the strainer and orifice from the two
drain lines. The modifications were accomplished prior to the
current startup, however, the strainer housings were left in place.
On October 9, 1985, a steam leak developed in a weld in one of the
drain lines ups ream of its strainer housing. The leak became
progressively worse necessitating a turbine shutdown. The leak was
repaired on October 12, 1985 by welding a " clam shell" cover over
the defective weld. During the remainder of the period, there were
three additional weld failures in this line including two field
repair welds and a shop weld. In addition, there was one weld
failure in the other drain line that contained a strainer housing.
Each of these failures necessitated removal of the turbine generator
from the grid and a reduction of reactor power to about 5-10% of
rated power.
The licensee identified the failure mechanism as high cycle fatigue
due to vibration with no evidence of corrosion. The licensee, in
conjunction with General Electric, developed and implemented,
shortly after this inspection period, a design modification to the
drain lines. This fix was effective in permitting the licensee to
complete testing at the 40% plateau, which will be as de.;ribed in
Inspection Report 50-289/85-25.
1.4 Summary
This inspection included continued progress of restart testing
activities up to the 40% power plateau. Throughout this period
there were several power reductions to 5-10% reactor power while
repairs were made to the weld failures in two of the drain lines
from the four main turbine control valve headers. The TMI-1 Restart
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Staff remained sensitive to an adverse impact on shift supervisor
safety duties due to NRC. shift inspector questioning and discussions
of matters of a programmatic nature. Accordingly, the shift
inspectors referred only implementation matters or status questions
to the shift supervisor and referred programmatic (event followup,
i design or procedure adequacy problems) to resident and region-based
NRC personnel. Resident and region-based personnel interfaced with
licensee support groups in followup to shift inspector referrals /
concerns. The staff's observations and findings regarding plant
operation and testing and_ licensee response to operational events is
discussed in the report sections that follow.
2. Shift Inspection Activities
2.1 Scope of Review and Observations
. During the period of October 11-18, 1985, the TMI-1 Restart Staff
! continued its augmented shift inspection coverage. The NRC shift
) inspectors assessed the adequacy and effectiveness of operating
personnel performance based on the inspectors' observations of
operating and startup activities to determine that:
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operators are attentive and responsive to plant parameters
and conditions;
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plant evolutions and testing are planned and properly
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procedures are used and followed as required by plant
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equipment status changes are appropriately documented and
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communicated to appropriate shift personnel;
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the operating conditions of plant equipment are
effectively monitored and appropriate corrective action is
initiated when required;
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backup instrumentation, measurements, and readings are
i used as appropriate when normal instrumentation is found
to be defective or out of tolerance;
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logkeeping is timely, accurate, and adequately reflects
plant activities and status;
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operators fqllow good operating practices in conducting
plant operations; and,
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operator actions are consistent with~ performance-oriented
training.
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The shift inspectors' observations included, but were not limited
to, those reactor plant operation and testing activities, periodic
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surveillance activities, and preventive and corrective maintenance
activities listed below.
; Reactor Plant Operation and Testing Activities
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routine control room operations including annunciator
alarm response
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operating and emergency procedures discussions with shift
supervisors, shift foremen, control room operators, and
shift technical advisors
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periodic inspection observation tours of areas'outside the
control room, including diesel generator rore,, emergency
feedwater rooms, control building, turbine building,
auxiliary building, intermediate building, electrical
switchgear rooms, and outside buildings and yard areas
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shift preparation briefings and conduct of turbine
overspeed trip testing
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operational preparations for removing train A of
extraction steam for weld repair
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power level increase to 25% of rated power
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integrated control system (ICS) tuning
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power level reddctions and increases including turbine
generator shutdown /startup for drain line weld repairs
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secondary plant auxiliary operator observation / readings
rounds
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fire drill ~in vicinity of hot machine shop
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power level increase to 40% of rated power with ICS fully
in automatic
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inspector verification of core flood tank valve breakers
j and building spray valve positions
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operator response to makeup total flow instrument MU-42-FI
failure high
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shift foreman response to loop A reactor coolant flow
nuisance alarm due to plant conditions at low power level
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crew briefings prior to major changes in operating power
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levels
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operator response to automatic turbir.e trip, while at 10
MWe, due to high moisture separator levels
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operating shift response to rod control shifting to manual
- after experiencing a motor fault
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Periodic Surveillance Activities
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reactor coolant system (RCS) leakage measurements
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RCS heat balance calculations
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reactor building 30 psig analog channel monthly test
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turbine-driven emergency feedwater pump functional test
and valve operability test
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reactor protection system channel D monthly test
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control rod movement test
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personnel airlock leak rate measurement
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nuclear service river water pumps and valves inservice
inspection testing
Preventive and Corrective Maintenance Activities
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auxiliary boiler B repairs
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repairs of weld leaks on secondary system steam line drain
piping downstream of turbine control valves
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main feedwater control valves A and B mechanical repairs
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integrated control system oscillation troubleshooting and
j repairs
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2.2 Assessments of Shift Inspectors
2.2.1 General
The shift inspectors assured that any potentially adverse
safety concern or regulatory finding was identified
promptly to both the licensee's shift supervisor and the
TMI-I Restart Manager. Those items requiring additional
staff review or followup are described in parag*aph 3 of
this report. Also, at the end of their assigned period of
shift inspection activities, the inspectors provided their
general assessment of facility operational readiness and
operating personnel performance. These general
assessments included, as applicable, each inspector's
overall views related to operations, technical support,
maintenance, surveillance, radiological controls,
training, emergency planning, physical security, and
housekeeping / fire protection. The inspectors' assessments
are presented below.
2.2.2 Operator Performance
In general, control room operators continued to
demonstrate their detailed knowledge of plant design and
current status of testing and operational activities.
Their operational abilities were rigorously challenged
during this period due to the numerous power. level changes
and minor transients induced because of integrated control
system (ICS) tuning problems. The operators were
successful in taking manual control of the ICS and
avoiding a significant transient that had the potential to
challenge safety-related system. This can be attributed
to their alertness and attentiveness to their duties in
overall control of the plant.
The team concept continued to be evident especially when
operators were in manual control of the ICS. These
situations demanded continuous and clear communications
-between control station operators because of the
effect that any one individual could have on the entire
plant. At times during these evolutions, communications
faultered and emotions got somewhat tense, but shift
supervision or licensee management stepped ir and controlled
the situation to avoid any major plant transient. During
other routine evolutions, control room operator communica-
tions became somewhat lax in that valve numbers were referred
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to without system designators. In no case did this lapse
of communications induce an ineffective exchange of infor-
mation resulting in an adverse safety situation. Control
room operator communications during routine and transient
situations will continue to be routinely followed during
shift inspector activities.
The shift inspectors continued to assess auxiliary operator
knowledge and performance by focusing on how they conducted
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their shift tours and discussing related observations and
their knowledge of plant equipment operability. In partic-
ular, several secondary auxiliary operators were quizzed on
how to take manual control of the-emergency feedwater (EFW)
flow control valves since that would be an emergency func g
tion in accordance with restart condition 1.p. All of the
auxiliary operators demonstrated an appropriate knowledge
of plant design for their positions including EFW manual
control. They demonstrated alertness and attentivess to
the numerous observations made on their tours. They kept
the control room operators informed of plant status condi-
tions as reflected in building spaces.
In general, procedures were properly implemented. Shift
inspectors noted that the ICS operating procedures did not
fit the unique conditions of plant operation for the current
mode (see paragraph 3.2.2). Further, certain operators
were observed eating in the center console area (see para-
graph 3.2.2). The proper use and implementation of facility
procedures will continue to be routinely followed during
shift inspector activities.
Overall, operators were formal and professional in their
activities. Minor errors were caught by more experienced
operators. Although some signs of inexperience showed
through, there were no questions by the TMI-1 Restart
Staff on the operators' ability to safely operate TMI-1,
2.2.3 Training
The numerous power level changes during this period provided
the operators with excellent opportunities to gain opera-
tional experience, especially when the ICS needed to be
operated in manual. The control room operators' simulator
training, in which manual operation of the ICS was quite
frequent, appeared to have been effective in preparing the
operators for the unique aspects of the test program. Shift
supervisor and licensee management continued their emphasis
on every event being a learning experience.
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2.2.4 Technical Support
Shift technical advisers continued to be effectively used
with the the operating shift. There were no recurrent
interface problems between operators and test engineers as
had been noted in the last inspection report.
2.2.5 Maintenance / Material Condition
The shift inspectors provided no significant adverse
comments, as noted.in paragraph 3.2.1, regarding the
material condition of the plant. Overall, they were
satisfied except for certain areas of the turbine
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building.
Equipment problems continued to be relatively few and
agressively pursued. Instrument and control (I&C)
technicians' troubleshooting efforts were coordinated well
with the control room operators. There was definite
maintenance management involvement and attention to daily
problems as evidenced by frequent visits to the control
room or to areas of interest in the plant.
2.2.6 Surveillance Testing
Surveillance activities were well coordinated with
operations department activities. Surveillance procedures
were properly implemented.
2.2.7 Radiological Control
The miminization of contamination areas was noticeable.
Contaminated material was properly secured. Areas were
properly posted with useful information. Health physics
personnel appeared conscientious in their duties and
properly conducted routine surveys.
2.2.8 Emergency Planning
No inspector observations were made in this area during
this period.
2.2.9 Security
Security personnel were observed making special patrols
during heavy fog and they were attentive to their duties.
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2.3 Conclusion
Control room operators not only continued to demonstrate their
detailed knowledge of the facility, but they also demonstrated their
ability to safely operate the plant especially in the manual mode of
ICS and avoid challenges to safety-related systems. An independent
shift organization and team concept continued throughout the inspection
period with little evidence of recurrent interface problems between
operators and test engineers. Auxiliary operators continued to
demonstrate an appropriate knowledge level. Maintenance department
personnel worked well with the on-shift organization. Overall, pro-
cedures were properly implemented. ' Effective on-the-job training was
achieved for operators and technicians. Proper radiological controls
were exhibited by all personnel observed. Overall, personnel con--
ducted themselves in a formal and professional manner.
3. Plant Operations
, 4 3.1 Routine Review ! TMI-1 Restart Staff inspectors periodically inspected the facility j to determine the licensee's compliance with general operating
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requirements of Section 6 of the Technical Specifications (TS) in
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the following areas:
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review of selected plant parameters for abnormal trends
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plant status from a maintenance / modification viewpoint
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including plant housekeeping and fire protection measures
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control of ongoing and special evolutions, including control
room personnel awareness of these evolutions
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control of documents including log-keeping practices
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implementation of radiological controls
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implementation of the security plan including access control,
boundary integrity and badging practices
The inspectors ,also focused their attention on the areas listed below.
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control' room operations during regular and backshift hours,
including frequent observation of activities in progress and
periodic reviews of selected sections of the shift foreman's
log and control room operator's log and other control room
daily logs
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followup items identified by shift inspector activities
(paragraph 2)
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areas outside the control room
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selected licensee planning meetings
As a result of this review, the ir.spectors reviewed specific events
in more detail as described in the sections that follow.
3.2 Findings
3.2.1 General
In general, housekeeping and fire protection measures
remained consistent with previous high standards in
safety-related areas. Cigarette butts and a moderate
amount of dust were noted on top of safety-related
switchgear in the control building. Apparently, this
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material was left over from the shutdown period during
which workers provided extensive structural steel fire-
proofing in the area. The dust is somewhat expected and
1 the material will be removed during preventive maintenance
on the switchgear. Also, licensee efforts to hold back
the boundaries for contaminated areas were notable in
permitting free access for management inspection purposes.
The turbine building continued to have cleanliness
problems with respect to the removal of temporary
structures built to support the previous long term outage.
( None of the conditions in the affected areas adversely
affected safe operation of the facility.
Overall, the material condition of the plant remained
- quite good. Plant performance continued to be as expected
with only minor safety-related equipment problems. The
main steam drain line leak was a persistent secondary
plant problem that delayed progress of the power
escalation test program.
Management involvement and attentiveness to daily
activities continued. The maintenance departments' daily
planning meetings were conducive to keep management
abreast of plant problems and to provide overall direction
to proceed deliberately and cautiously during the special
test sequences.
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Management continued to insist on briefings, critiques and
reviews of plant experiences. The overall direction by
operations management appeared to have a calming effect on
the results of pre-test activities rather than one of
interference with progress. Noise control in the control
room continued to be demonstrated. The results of the
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staff's review followup to shift inspector referrals and
to those reactive items identified collectively by the
TMI-1 Restart Staff as warranting appropriate NRC followup
action are summarized below.
3.2.2 Thermocouple Operability
During a control room inspection, the inspector determined
that four of the fifty-two incore thermocouples were
inoperable. Three of the four inoperable thermocouples
were located in the same quadrant of the core. The
inspector questioned the licensee if these inoperable
thermocouples complied with Technical Specifications Table
3.5-2 which requires a minimum of two thermocouples per core
quadrant to be operable. The licensee stated that the
requirement was met because the backup incore readout
, (BIRO) thermocouples has 16 thermocouples with 4 per
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quadrant and this was for the inadequate core cooling
instrumentation referred to in the TS. The BIRO
thermocouples are checked on a monthly basis in accordance
with surveillance procedure 1302-21. As an independent
check, the inspector requested a control room operator to
obtain a reading for all 16 incore thermocouples. The
inspector compared the reading to plant conditions and
concluded that the BIRO system was functioning properly.
3.2.3 ICS procedure Adequacy
On several occasions shift inspectors noted that operators
would place the operating main feedwater pump in manual
control (hand control) when starting additional ~ condensate
booster pumps or placing a second feedwater pump in opera-
tion. These provisions were not dictated in the controlling
procedure Operating Procedure 1105-4, " Integrated Control
System," dated February 25, 1985. The inspector reviewed
this procedure to assuro the procedure was technically
adequate and that the procedure could be used as written.
The inspector determined the procedure properly addressed
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the operations of the integrated control system (ICS);
however, it was silent as to how the operators were
currently operating the ICS. The licensee representative
stated that taking manual control of the feedwater pump
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was performed so that starting of additional equipment
would not cause a small feedwater transient with ICS still
in a tuning stage.
The inspector reviewed the strip charts of associated
parameters and determined that the licensee's statement
about the potential for transients was correct. The
inspector concluded that although the licensee's approach
was correct the procedure should reflect the actual specific
steps on how to control the plant. The plant operations
manager stated that, because the ICS had not been fully
tuned, it was prudent to take manual control to avoid
transient conditions. If the ICS could not be tuned so
that starting additional equipment would not cause
controller cycling, the procedure would be changed. The
inspector found this approach acceptable.
The inspectors noted at certain times that the licensee
was experiencing minor control problems with the ICS in
automatic. On one occasion the inspector noted that the
licensee required additional operators on the control
panels. In one instance the of plant operations manager
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required the additional operators to eat their meals in
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the control room to ensure they were readily available.
The inspector noted that Administrative Procedure 1029,
step 5.2.g.6 states that meals shall not be eaten at the
control console area, however, this restriction does not
apply to eating or drinking a single item. The inspector
noted that there were extra operators at the console and
that' eating did not interfere with operations nor was the
eating-done directly over control panels.
The inspector discussed the issue with the plant
operations manager who stated that'he had given a one time
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permission to do this and that eating food was not to
interfere with operations. The on-shift NRC inspector
independently verified this to be true. The inspector
determined that licensee management did not,
intentionally, circumvent station procedures as standard
, practice and considered this instance an isolated case.
The inspector concurred with the plant operations
manager's concern and action oriented toward safe plant
operations by keeping operators close to the panels under
these unique conditions. The inspector had no further
,
comments in this area.
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3.2.4 Reactor Protection ~ System Breaker Replacement
As noted in NRC Inspection Report 50-289/85-22,
(Unresolved Item 289/85-22-05) the licensee shipped the
failed breaker CB-10 and breaker CB-11 that indicated some
wear to General Electric (GE) in Atlanta, Georgia, for
further evaluation. After inspection of breaker CB-11,
GE, with GPUN concurrence, replaced the operating
mechanism of CB-11 using parts from a spare GPUN breaker.
After rebuilding and testing breaker CB-21, it was
returned'to the site.
On October 16, 1985, the licensee reinstalled breaker
CB-11 into the reactor protective system. Preventive
Maintenance procedure E-36, "CRD TRIP Breaker Trip Test,"
was performed. In addition, once the breaker was in
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place, applicable sections of Surveillance Procedure
1303-4.1, " Reactor Protection System," were conducted.
The inspector witnessed the installation of the breaker
and subsequent testing. The inspector also performed a
visual inspection of the breaker. This inspection did not
identify any damage from shipment or any evidence of
, internal misalignment. '
While witnessing SP 1303-4.11, the electrician performing
the test inadvertently tripped the breaker by going to
shunt-trip instead of undervoltage (UV) trip. Licensee
representatives were following the procedure; however, it
appeared that the electrician was not familiar with the
procedure. This'was compounded by the fact that the
licensee was using a page phone instead of a headset to
maintain communications with'the control room where the
. evolution was being controlled. Immediately the mainten-
. ance supervisor, present at the RPS breaker, recognized the i
situation and took control. He ordered that an I&C
technician (individuals who normally perform the test)
perform the test and communications be established with a
headset at the breaker panel.
In addition to witnessing the testing of the breaker, the
inspector reviewed the receipt inspection package and job
ticket CH-798. No discrepancies were noted.
In a related matter, a shift NRC inspector noted that the
spare RPS breakers were being stored in the turbine
building switchgear room. The inspector brought this to
l the attention of the licensee who immediately placed the !
breakers in a more secure space. The licensee also stated
. - , - -
- - .- . . .- .
. - . .
., .,
'
17
that before an RPS breaker is installed the applicable
preventive maintenance procedure will be performed. This
procedure requires a visual inspection. The inspector
reviewed the licensee's applicable procedures and
concluded that they were adequate to determine if the
breaker had been physically damaged and that the required
testing in place would determine if the breaker was
electrically inoperable. Discussions with the licensee
indicated that the long-term solution to the breaker
storage problem would be resolved once the breakers were
properly designated as spare parts and placed in the
warehouse inventory. The inspector had no further
comments.
3.2.5 Lift of MS-V22A/B During Emergency Feed Pump Operation
On several occasions during the operation of emergency
feedwater pump (EF-P-1) on main steam pressure, the
feedwater pump turbine relief valves (MS-V22A/B) would
lift. This was described in detail in NRC Inspection
Report 50-289/85-22, (Unresolved Item 189/85-22-03). The
licensee committed in a letter dated October 11, 1985,
from H. Hukill, GPUN, to T. Murley, NRC, to develop and
provide specific guidance to the operators. The licensee
issued Operations Department Memo No.85-6, dated October
16, 1985, which addressed lifting of MS-V22A/B during
EF-P-1 operation. The inspector reviewed the specific
guidance given in the operations department memorandum and
concluded that it correctly reflected the commitments in
the licensee's letter.
3.2.6 Work in Safety-Related Areas
During an inspection of safety-related building spaces on
October 16, 1985, the inspector observed that a contractor
employee was standing on the "Limitorque" operator for
FW-V92A which was about 20 feet off the floor at the
intermediate / turbine building interface area. The valve
FW-92A is a block valve for the startup feedwater flow
control valve; and, since the plant was operating at 40%
power, this valve and the associated regulating valve were
open supplying feedwater, in part, to the "A" steam
generator. The individual was erecting scaffolding in the
area. 1
l
l
._
.. '.
.
18
,
When the observation was brought to the attention of the
operation manager, immediate action was initiated to
assure that the individual no longer used any valve
operators in that area for standing support in the
construction of the scaffolding. Later observations by
the inspector confirmed effective results.
The inspector expressed concern that workers using valve
bodies or operators for construction support work created
the. potential for an adverse safety impact in that a
transient could result due to inadvertent opening / closing
or malfunctioning of an affected valve. The transient
could result in.an unnecessary challenge to a safety
system and the operators. Licensee management s
acknowledged the inspector's concerns and agreed to review
this matter with the responsible onsite departments. This
area will continue to be routinely followed by the TMI-1
Restart Staff throughout power escalation testing and
subsequent power operations.
3.2.7 Nuclear Service River Water ISI Survei11ance
On October 17, 1985, the inspectors observed the
performance of an inservice inspection (ISI) surveillance
on the nuclear service' river water (NSRW) system.
Surveillance Procedure (SP) 1300-3I A/8, Revision 23,
dated August 20, 1985, was used by two auxiliary operators
to perform this surveillance.
The inspectors concluded that this ISI was performed in
accordance with procedures and no adverse conditions were
observed.
3.3 Conclusion
No major equipment problems existed that adversely affect safe
operation of the facility. Procedures were adequate to support
operations and they were properly used and implemented. Licensee
management, in general, demonstrated overall control, attentiveness,
and s conservative approach to the safe operation of the facility
and to the equipment problems. The secondary plant drain line
problem presented an obstacle to continued startup testing. The
observation of the worker on the valve operator coupled with the
latest inspection report findings are indicative of a need for
better control of personnel workin'g in safety-related areas.
. . . .
.. _. _-.
,
* '
.. .
I
19
4
4. Startup Tssting
4.1 Power Level Plateau Data Review
Test results from the test program for the power plateaus of 15% and
25% were reviewed by the inspector to verify that:
!
--
test changes were approved and implemented in accordance
with administrative procedures;
i --
changes did not impact the basic objectives of the test;
'
--
test deficiencies and exceptions were properly identified,
- resolved, and resolution accepted;
--
the cognizant engineering group had evaluated the test
results and signified that testing demonstrated design
conditions were met; and,
I --
~
test results compared with established acceptance criteria
,
or were properly resolved.
The startup tests reviewed for this verification included:
--
TP 800/5, " Unit Load Steady State Test," (15% and 25%);
- --
TP 836/1, "Feedwater System Operation and Tuning," (15%);
--
TP 846/1, "Incore Thermocouple Functional Test at Power,"
(15%);
--
TP 849/1, "ICS Tuning," (15% and 25%); i
--
SP 1303-11.19, " Turbine Overspeed Testing;"
--
SP 1302-1.1, " Power Range Calibration;" and,
--
OP 1105-14, " Loose Parts Vibration Monitoring Data."
The details and findings of this review are described below.
4.2 Findings
c
4. 2.1 - Unit Load Steady State Test
Important plant parameters such as reactor coolant inlet
and outlet temperatures, steam generator level,
, temperature, outlet pressure, and feedwater flow and'
temperature were measured at the 15% and 25% power
J
,
-m ,- -. - - ,w-, ---g--+
.
'.. ..
20
plateaus. The measured data at the 25% power level showed
excellent agreement with the predicted values. However,
at the 15% power level, some deviations were noted. The
licensee and its NSSS vendor (B&W) are evaluating these
data. The steady state 15% power level data will be
collected again when the unit returns to this power level
after the completion of TP 800/8, "RCS Overcooling Test."
4.2.2 Feedwater System Operation and Tuning
r' The feedwater heater drain system was checked at the 15%
power level. No unacceptable conditions were identified.
During this test, level indication in the sixth stage
~ drain collecting tank (LI-74) was found out of the
acceptable range. This problem was subsequently
corrected. Test procedure TP 836/1, step 9.3 calls for
checking system response at-the 25% power level when two
heater drain pumps are running. Due to the fact that only
one heater drain pump was running during the test period,
this part of the test was postponed until after the return
to 48%'of rated power.
4.2.3 Incore Thermocouple (T/C) Functional Test
The incore T/Cs were checked at the 15% power level; 4 out
of 52 T/Cs were out of service during this test. The
inspector noted the following results:
--
The readings from symmetrical T/Cs agreed within
+/- 1% of the symmetrical group average readings
or corresponding paired T/C reading.
---
T/C readings agreed within +/- 2% of the cal-
culated values based on expected temperature
distribution in the core.
--
At 15% power level, the T/C readings were very
close to each other. The five highest incore T/C
readings ~as selected by the program "TCDSPL" did
not necessarily agree with the five highest T/C
readings from the Mod Comp computer which were
taken at a slightly different time. The licensee
designated this as a test deficiency. This matter
will be tracked further at a higher power level
-by the licensee and TMI-1 Restart Staff.
. -- . - . .-. . - -
_. . ._- - _
*
.
.. .
21
--
The plant computer uses the program "TCDSPL" to
select the five highest incore T/C readings and
. calculate the saturation margin. The accuracy of
this calculation was verified by hand calculation
in accordance with the procedure. The result
< indicated that the "TCDSPL" program accurately
calculated the saturation margin with a 1.3
degrees F deviation from the hand calculation.
--
The backup incore readout (BIRO) thermocouple
display and the value displayed on the operator's
group was onsistent and agreed within the
, established acceptance criterion of +/- 16
4
degrees F.
! 4.2.4 Loose Parts Monitor System Test
During power escalation testing, the licensee is taking
base line data for-the loose parts monitor system (LPMS)
at each power level plateau identified on the testing
sequence. Operating Procedure (0P) 1150-14, " Loose Parts
Monitor System," is being used to operate the system and
tape record base line noise levels. The tapes are being
'
sent to B&W for analysis. During the reactor trip at 40%
power, base line data will be taken both before and after
the trip. -
The inspector reviewed OP 1105-14 and noted that it was
classified as "not important to safety." This
-clarification was confirmed with the licensee's QA
representatives.
OP 1105-14, paragraph 3.2.a, requires that the LPMS
cabinet be inspected once per shift when the reactor
coolant pumps are running and that alarm lights be
reported. Paragraph 3.2.c requires that each of the LPMS
channels be monitored for noise once per shift in the
control room or at LpMS cabinet. Neither was being
performed.
Discussions with an operations engineer indicated that
, failure to check for noise levels was an oversight. The
control room shift and daily logs (non-technical
specification required) was immediately revised to check
,
for LPMS noise on the speaker located in the control room.
J I
- _
_ ,, _ _ . , -_ . _ _ . _ _ , , . . _ _ . .
._. . - . - _ . . . _. .
'.. '. .
22
The operations engineer stated further that the LPMS now
has a common alarm in the control room which had not
existed previously. If this alarm is received, the local '
<
alarm panel can be checked. Since this alarm is monitored
continuously, the intent of OP 1105-14 LPMS alarm
monitoring had been met. He stated that no change to OP
'
1105-14 was required at this time but a change would be
considered during procedure OP 1105-14 biennial review.
The inspector concurred with the licensee resolution and
had no further questions at. this time.
4.2.5 Main Turbine Overspeed Test
I Test C of SP 1303-11.19 specifies that the turbine generator
overspeed trip setting should be between 1980-1998. The
actual trip occurred at 1960 RPM. This value was accepted
as satisfactory since the procedure states that if the trip
setting is below 1980 the turbine can be returned to service.
However, the turbine will likely trip on overspeed if full
l load is lost. Trips above the 1998 setting are unacceptable
and must be repaired prior to putting the turbine back on
line. All other data in the procedure was satisfactory.
This test met TS 4.1.1 and Table 4.1-1 requirements.
-4.3 Reactor Coolant System Leak Rate Surveillance
.
The inspector reviewed the reactor coolant system (RCS) leak rate
4
surveillance (SP-1303-1.1) results from October 1-15, 1985. The
results indicated that during this period, the RCS leakage was well
within the TS limits.
The unidentified leak rate as calculated by the licensee was
independently analyzed by the inspector (Figure 1). The sampling
data indicated that the average unidentified leak rate was (-)0.21
gpm with a standard deviation of 0.11 gpm. A relatively large
variation occurred from October 5-14, 1985. This was expected due
to operating conditions and required power maneuvering during this
period. The calculated leak rate is highly affected by the Tave
- value, and Tave is very sensitive to power changes when the power
level is below 15%. The inspector also performed an independent
calculation using an NRC-developed leak rate computer program (RCSLK
9) for the leak rate determination on 1835-2035 October 15, 1985.
The comparison results are shown below:
) i I i 4
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FIGURE 1
_ __ _ ., __ . _
*
.. ..
23
i i
Leak Rate (gpm) Licensee Calculation Inspector Calculation
Leakage Plus Losses
'
0.0772 0.07
1
Unidentified Leak Rate -0.2217 -0.06
'
The results from the inspector's calculation agreed closely with the
licensee's calculation for the leakage plus losses term. The
difference in the unidentified leak rate calculation is due to a
correction factor of 0.1644 gpm being included in the licensee's
calculation. The applicability of this correction factor is being
reviewed by NRR.
4.4 Primary to Secondary Leak Rate Monitoring
l
The licensee monitors the primary to secondary leakage per
surveillance procedure 1301-1, " Shift and Daily Checks," Revision
58. The inspector reviewed the surveillance results from October
; 9-15, 1985. The calculated results indicated that the leak rate was
'
'
about 0.2 gph, which is consistent with a previous krypton leak test
result. No indication of once through steam generator (OTSG) tube
- degradation was noticed from these data reviews.
! 4.5 Conclusion ! I
Testing for the 15% and 25% power plateaus was accomplished in
accordance with procedures, data were acceptable, and test
objectives were met. Licensee management was responsive to
inspector observations. Problem areas were quickly corrected and
actions were taken to preclude their recurrence. Overall licensee
"
l performance in the test area can be considered acceptable and, to
1
date, test results are acceptable.
5. Decay Heat Removal System Procedure Review
] 5.1 Review
,
! The inspector reviewed operating procedure 1104-4, " Decay Heat i Removal System," Revision 54, dated September 5, 1985, to ascertain i
whether it is in accordance with regulatory requirements and whether
t
its technical adequacy is consistent with desired actions and modes
of operation. As part of this review, the inspector also examined
, the following documents. 1 i
. - - .- - - __ . . - .
'.. -
. .
24
--
GAI drawing C-302-640, Revision 37, " Decay Heat Removal;"
--
TMI-1 Operations Plant Manual, Section B-6, Revision 1, " Decay
Heat Removal System;" and,
- --
ANSI N18.7-1976, " Administrative Controls and Quality Assurance
for the Operational Phase of Nuclear Power Plants."
f
In addition to the above, the inspector toured both decay heat vaults.
The valve lineup verification was completed during the week of
September 30, 1985, just prior to restart.
l 5.2 Findings
i The inspector determined that the procedure's stepwise instructions
.
were compatible with checklist information, and provisions for
! signoffs were evident. Appropriate limitations, such as pressure /
l temperature limits, cooldown ratios, and net positive suction head
requirements were correctly incorporated into the procedure.
Various precautions and notes concerning equipment and
) administrative operability requirements, and appropriate technical
specification requirements were also incorporated into the
i procedure. The startup valve checklist and the P&ID (Piping and j Instrument Diagram) were compatible and agreed with each other. I
During the tour of the "A" & "B" decay heat vaults, the inspector
found them to be clean and neat. There was very little extraneous
material in the "B" decay heat vault; the "A" decay heat vault was
being painted at the time of the tour. Painting equipment that was
left in the "A" decay heat vault during non painting hours was kept . to a minimum, was neatly stored in a' safe corner of the vault and
] did not pose a fire or safety hazard.
The inspector found an out-of-date calibration sticker on pressure
transmitter DH7-PT1. The inspector found that the instrument was
actually calibrated on August 13, 1982; this instrument is to be
!
calibrated every six years. This item was noted to the licensee and
the inspector had no further questions. '
'
Before exiting the auxiliary building, the inspector decided to
watch the painting crew enter the "A" decay heat vault. Upon
rounding a corner of the building wall, the inspector saw a painter
'
straddling an RWP boundary. The inspector was unable to determine
if the worker was entering the RWP area or if he had previously
entered the area and had half exited it to retrieve painting
i equipment. The inspector brought this situation to the attention of
the group radiological controls (Radcon) supervisor.
1 i 1
- <, m. , , .-,m-. m.,- - - . - - . . ,c , . - _ . - ,-._.,.,,,,,m.-.
* *
. .
25
The radcon department's review of this matter revealed that the
individual was entering the contaminated area. The radcon
department was responsive to the inspector's concern on proper
contamination control and he had no further comments on this matter.
5.3 Conclusion
s The inspector determined that procedure 1104-4 is adequate to
control safety-related operations within applicable regulatory
requirements. If called upon, this procedure can be used for
operations to remove decay heat from the core after the plant is
shutdown. No adverse conditions were found that would affect plant
safety.
6. Licensed Operator Requalification/ Restart Training
6.1 Restart Hearing Issues
The licensed operator requalification training program was reviewed
to ascertain its conformance to the restart requirements contained
in H. Denton's letter to H. Hukill, dated October 2, 1985, and items
identified by the Atomic Safety Licensing Board.
6.1.1 Restart Condition 5.a requires that in October of each year
the licensee report on the progress towards installation of
a TMI-1 exact replica simulator. The licensee letter dated
October 3, 1985, from H. Hukill, GPUN, to J. Stolz, NRR
provides that report for 1985. The present schedule is for
delivery of the simulator on site in June 1986, and training
on the simulator to begin in August 1986. The inspector
concluded that the licensee complies with Restart Condition
5.a.
6.1.2 Restart Condition 5.b required that until the exact
replica simulator is in use the licensee was to provide at
least one week of basic principles trainer (BPT) time for
licensed operators. The training department has
integrated the BPT into the requalification program. Each
requalification cycle, which is normally a five day
training period, includes at least one 6-hour training
session on the BPT. Presently the 1985 requalification
program, which contains five cycles, has 38 hours of
. training on the BPT spread over eight days. The training
department is planning on incorporating an additional nine
hours of BPT.use into the present requalification program.
. - - . - - .- . - . - . - _-.. .- .. '..
! 26 i ! i In addition *.o BPT training, one week of training at the
B&W simulator in Lynchburg, Virginia, was provided to each
i
licensed operator. The inspector concluded that the
! licensee complies with restart condition 5.b. . 6.1.3 The certification files of three licensed instructors were < 2
inspected. Each file contained the instructor's
certification and completed performance evaluation forms.
Each instructor has been evaluated at least eight times in
the past year by at least five different evaluators. A
t review of the evaluation schedule showed all instructors
!
had been evaluated with the periodicity and at the levels
4
required by the Instructor Evaluation Procedure '
6200-ADM-2607.01. The licensee's instructor evaluation
program is in place and being properly implemented. The
inspector concluded that the licensee complies with their
commitments made as a result of the restart hearing.
- 6.1.4 The inspector reviewed ten sets of weekly quizzes, which
had been administered during the 1985 requalification
- , program. Licensee instructors had evaluated all sets of
weekly quizzes for collusion between at least half of the
'
.
operators taking the quiz for at least 25'4 of the questions,
as required by the licensee's collusion check program. No
- instances of collusion were found by the instructors. The
j inspector determined that the licensee's collusion check j program is in place and being properly implemented. The i inspector concluded that the licensee complies with their , commitments made as a result of the restart hearing.
; 6.1.5 As a result of the reopened hearing on the training
! program and in reference to the ASLB Partial Initial j Decision (PIO) dated May 3, 1985, the licensee has '
developed a procedure, " Trainee Evaluation - Once Back -
On-the-Job", 6200-ADM-2682.10, which became effective
! September 13, 1985. However, this procedure is not
expected to be implemented-for licensed operators until
}'
mid 1986. The proper evaluation of trainees to meet ASLB
hearing requirements is unresolved pending completion of
licensee action and subsequent NRC Region I review :
l i
(50-289/85-24-01).
! 6.2 Requalification Program Review
In addition to the review of the above elements in the
requalification program, the inspector reviewed the development
1
process for determining which items were to be included in the 1985
j requalification program. The inspector assured compliance with 10 i l
i
l
! '
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. .
27
CFR 55, Appendix A. The training department used a formalized system of
evaluating training requests from licensed operators and evaluating
weaknesses identified by the annual examination. These evaluations
were then used to assist in the selected of the requalification
program topics.
The content of the weekly quizzes and annual requalification
examinations was reviewed.
6.3 Requalification Program Finding
The questions were well constructed and minimal use was made of
true-false, multiple choice questions.
A review of the attendance records found that some licensed
operators who were not assigned to an operating shift had not
attended all requalification lectures. One operator had been
specifically exempted by letter and the other operators had not
exceeded the allowed limit for missed lectures. All licensed
operators had completed the weekly quizzes.
A review of the grades on the annual requalification examination
showed grades ranging from 75*4 to 95's and averaging about 85%.
Three operators failed the examination with overall grades less than
70%. On the retake examination, two of the operators passed with
overall grades between 80*4 and 85%, and one operator failed. The
operator who failed the retake examination has been removed
permanently from licensed duties. The grades on the requalification
examination, the grades on the retake examination, and the handling
of examination failures is indicative of an effective training
program that uses examinations to differentiate between operators
who have retained the requalification training and those who have
not.
6.4 Conclusion
The requalification program is well organized and documented. It
conforms to applicable regulations and restart requirements.
7. Gaseous Radioactive Release Assessment
The licensee's program for quantifying and controlling gaseous
radioactive releases incident to the startup of Unit I was reviewed
against the criteria specified in Technical Specification 3.22.2,
" Gaseous Effluents," 10 CFR 50, Appendix I, and 10 CFR 20.106,
" Radioactivity in Effluents to Unrestricted Areas."
. _ - . . - -
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28
Currently, primary to secondary leakage is occurring at the rate of
approximately 0.2 gallons per hour, which results in detectable activity
in the main steam system. The measured concentration in the main steam
system is ~5.0 E-8 uCi/cc, primarily Xe-135. However, non-condensible
gases are concentrated in the condenser and discharged to the environment
via the condenser offgas system.
The condenser offgas is continuously monitored and recorded by radiation
monitor RMA-5. Nominal values for RMA-5 are about 60 counts per minute
(cpm) but at the end of the period, the monitor indicated 100 to 150 cpm.
Daily grab samples from RMA-5 indicate that the highest activity measured
since restart of TMI-I was 5.77 E-7 uC1/cc, Xe-133 and 5.46 E-7 uCi/cc,
Xe-135. The 10 CFR 20, Appendix B, Table II, unrestricted limits of 3.0
E-7 uC1/ce, Xe-133 and 1.0 E-7 uCi/cc, Xe-135 are concentration values
which may be averaged over a one year period and provide the basis for
the applicable Technical Specification 3.22.2.2(b) dose limits.
.
The Technical Specifications limit the air dose due to noble gases
!
released in gaseous effluents during any calendar year to < 10 mrad for
gamma radiation and < 20 mrad for beta radiation. Applying the
1 calculation methodology described in the ifcensee's NRC-approved Offsite
- Dose Calculation Manual (ODCM). The following table depicts activity
released via this pathway between October 8 and October 16, 1985.
I
Fraction of Yearly Limit ,
Total Cumulative Air Dose Technical Specification
l Activity Released at the Site Boundary 3.22.2.2(b) ,
3279 uC1, Xe-133 2.2 E-5 mrad, gamma 0.00022 % of the gamma air dose limit
5624 uC1, Xe-135 3.2.E-5 mrad, beta 0.00016 % of.the beta air dose limit
This analysis indicates that the resulting exposure due to these releases
to the environment is negligible with respect to regulatory limits.
,
During this inspection the licensee's methods and assumptions used to
postulate dose due to the releases to the environment _from the actuation
of atmospheric and safety relief valves associated with the main steam
system were reviewed. The licensee's " worst case" analysis assumed all
4
valves relieving continuously, i.e., MS-V4 A/B, MS-V21 A/B and MS-V17-20
A/8/C/D, for the duration of a year; and was based on the highest
measured concentration at RMA-5, 5.77 E-7 uCi/cc, Xe-133 and 5.46 E-7
uCi/cc, Xe-135. Application of the 00CM indicated the results shown in
the table below.
, I J
_ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _
- . - . - . -_ .-. . _ . __- - - .
. ,
,
29
-
Fraction of Yearly Limit
- Technical Specification
l Cumulative Air Dose 3.22.2.2(b)
3.6 E-8 mrad /sec, gamma (3.25 E7 sec/yr) = 11% of gar.na air dose limit
,
1.13 mrad /yr
'
5.7 E-8 mrad /sec, beta (3.15 E7 sec/yr) = 9% of beta air dose limit .
1.8 mrad /yr
l
,
This analysis indicates that any steam relief with the current secondary
^
side source term would result in negligible exposure with respect to
regulatory limits.
The licensee's calculational techniques and conclusions were
4
independently verified by the inspector, indicating that the assessment
methods and assumptions were valid for the control and assessment of
gaseous effluents via this pathway.
l-
8. Licensee Action on Previous Inspection Findings
,
8.1 (Closed) Unresolved Item (289/85-22-03): Licensee to issue interim
guidance for inadvertent safety valve lift on initiation of turbine
j driven emergency feedwater pump. See Detail paragraph 3.2.4.
8.2 (0 pen) Unresolved Item (289/85-22-05): Licensee to replace
unfurbished reactor protection system ac breaker. Licensee
2
evaluation of vendor information remains open. See Details
paragraph 3.2.3.
9. Exit Interview
4
The inspectors discussed the inspection scope and findings with licensee
management at the exit interview conducted on October 18, 1985. The
- 'following licensee personnel attended the final exit meeting
. ! J. Colitz, Plant Engineer Director ! J. Donnachte Jr., Radiological Engineer
C. Incorvati, Audit Supervisor
L. Pitter, Operations Administrative Assistant
R. Maag, Licensed Operator Training Supervisor
4 W. Nickel, Superintendent (Catalytic, Inc.)
L. Robinson, Communications Representative
i J. Ross, Manager Plant Operations
D. Shovlin, Manager Plant Maintenance
, C. Smyth, TMI-1 Licensing Manager ,
R. Toole, Operations and Mainte.iance Director
G. Troffer, TMI Maintenance and Construction Director (Acting)
'
D. Tuttle, Radiological Contrcls Field Manager
S. Williams, Radiological Engineer
i e 4
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'30
The exit meeting was also attended by S. Maingi, a nuclear engineer I
representing the Commonwealth of Pennsylvania. As discussed at the
meeting, the inspection results are summarized in the cover page of the
inspection report. Licensee representatives indicated that none of the
subjects discussed contained proprietary information.
Unresolved items are matters about which information is required in order
to ascertain whether they are acceptable items, violations or deviations.
Unresolved item (s), discussed during the exit meeting, are documented in
paragraphs 6.1.5 and 8.
.
I
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