ML20133H174
| ML20133H174 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 07/17/1985 |
| From: | Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20133H133 | List: |
| References | |
| 50-289-85-19, NUDOCS 8508090217 | |
| Download: ML20133H174 (40) | |
See also: IR 05000289/1985019
Text
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-289/85-19
Docket No.
50-289
License No.
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: May 31, 1985 - June 28, 1985
Inspectors:
N. Blumberg, Lead Reactor Engineer, Region I
J. Bryant, Senior Resident Inspector (Oconee), Region II
B. Burgess, Project Inspector, Region III
E. Gray, Lead Reactor Engineer, Region I
D. Haverkamp, Technical Assistant for TMI-1 Restart,
Region I
- T. Peebles, Senior Resident Inspector (Turkey Point),
Region II
M. Schaeffer, Reactor Engineer, Region I
R. Urban, Reactor Engineer, Region I
P. Wen, Reactor Engineer, 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 familiariza-
tion training and facility orientation.
Approved By:
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h
[nR. Conte,Tiil-1RestaQManager
Date
- TMI-1 Restart Staff
Division.of Reactor Projects
8500090217 850718
ADOCK 05000209
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Inspecticn Summary:
This special safety inspection (448 hours0.00519 days <br />0.124 hours <br />7.407407e-4 weeks <br />1.70464e-4 months <br />) reviewed shift activities and hot
shutdown plant activities in preparation for TMI-1 restart. Specific items
reviewed included Commission conditions for TMI-1 restart, an inadvertent
safety injection actuation, surveillance testing preparatory to restart, steam
generator and restart hearing license condition implementation, postulated
loss of feedwater transient at the facility, corporate activities in the
quality assurance end modification control areas, removal of diesel generator
interpole connectors, facility systems and equipment readiness for restart,
TMI-1 replica simulator design questions, and licensee action on previous
inspection findings.
Inspection Results:
Licensee management and quality assurance department personnel continued their
detailed involvement in plant activities. Overall, procedures were properly
implemented with a deliberate step-by-step approach, however, one instance was
identified in which an isolation valve was not restored to its open position
(violation, paragraph 2.2).
In addition, an inadvertent safety injection
actuation was caused by personnel errors, apparently due to those individuals'
unfamiliarity with the surveillance procedure. Overall, surveillance data
reflected operations within technical specifications limits.
The licensee
complies with applicable steam generator and restart hearing license condi-
tions, although the TMI-1 Restart Staff experienced some difficulties in
ascertaining compliance with certain conditions for various reasons. Adequate
procedures cover a loss of feedwater transient, and they implement many of the
conditions and commitments that resulted from the restart hearing. The licensee
has continued to implement initiatives in the modification control program.
Licensee corrective actions in response to the potential for diesel generator
interpole connector cracking were deliberate, well thought out and responsive
to NRC concerns.
The licensee resolved both previous and recent NRC issues
with respect to making plant equipment physically ready to restart, and there
were no physical obstacles to restart of the facility as of the close of the
inspection period.
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OETAILS
1.0 Introduction
1.1 Commission Conditions to Restart of TMI-1
By Memorandum and Order CLI-85-09, dated May 29, 1985, the Commis-
sion issued a decision that lifted the effectiveness of previous
orders directing that Three Mile Island Unit I (TMI-1) remain shut
down.
That action by the Commission permitted TMI-1 to resume
operation, subject to satisfactory completion of the conditions
imposed in the May 29, 1985 Order.
CLI-85-09 described the various
considerations, bases and reasons that were related to their deci-
sion to permit TMI-1 operation.
However, as described in CLI-85-09,
the Commission noted that TMI-1 has been shut down for over six
years.
The Commission believed that:
" ...because of this consideration alone that the power level
should be raised gradually to ensure that all components of the
facility still function properly, and that there is an adequate
opportunity to operate the plant at low power levels....
Furthermore, because the facility has not operated for six
years, the Commission has determined that licensee's perfor-
mance during the period of startup and power ascension, begin-
ning with initial criticality, should be carefully monitored
and thoroughly evaluated. During this time period, and any
time period thereafter the staff feels to be appropriate, the
staff is to provide more oversight to TMI-1 than it would
normally give an operating reactor."
As further stated in CLI-85-09, the Commission imposed in their
decision the following two conditions:
"(1) To ensure a safe return to operation, licensee is to
submit a power ascension schedule, with hold points as
necessary at appropriate power levels, to the NRC staff
for staf f's approval .
The plant cannot be restarted prior
to staff approval of such a schedule; and
(2) The NRC staff prior to restart is to provide to the
Commission for its information a general description of a
program to provide increased NRC oversight at TMI-1...."
The licensee's power ascensicn schedule for restart of TMI-1 was
described in a letter, dated May 31, 1985, from H. D. Hukill, Direc-
tor, TMI-1, to Dr. T. E. Murley, Regional Administrator, NRC
Region I.
That letter provided a description of the detailed
sequence of the restart power ascension test program, scheduled to
take 99 days.
In addition, the licensee committed to obtain verbal
authorization from the Region I Regional Administrator prior to
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proceeding beyond six specified hold points. The NRC staff's review
and acceptance of the power ascension schedule and hold points for
TMI-1 restart were documented in a letter, dated June 3, 1985, from
T. E. Murley to H. D. Hukill, thus satisfying the first of the two
above-stated Commission conditions.
The NRC staff's augmented inspection program for TMI-1 restart was
described in a memorandum, dated June 5, 1985, from W. J. Dircks,
Executive Director for Operations, for the Commissioners. That
memorandum discussed the steps being taken to monitor restart
activities more aggressively in order that the staff can verify in a
reasonable period of time that operational activities are being
ctrried out satisfactorily.
Those steps include the establishment
of a saparate organization (TMI-1 Restart Staff) to manage and
coorainate the NRC efforts.
This organization is directed by a
seafor NRC manager and is composed of three separate staff compo-
sents (resident inspection staff, operational assessment staff and
support staff), as depicted in Figure 1.
The unique component of
the restart staff is the operational assessment staff which is
comprised of NRC inspectors from Regions II and III and NRC contrac-
tor operator licensing examiners from Battelle Pacific Northwest
Laboratory (PNL) and EG&G, Idaho.
These individuals (all of whom
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have experience with B&W reactors) will be assigned to observe the
conduct of control room operators and licensed activities performed
in other plant areas. The functions of the TMI-1 Restart Staff were
described generally in the June 5, 1985 memorandum, and the scope of
augmented NRC inspection coverage during the various phases of the
licensee's restart program is as depicted in Figure 2, thus satisfy-
ing the second of the above Commission conditions.
1.2 TMI-1 Restart Staff Activities and Facility Operations Summary
The NRC TMI-1 Restart Staff functions and respinsibilities have been
delineated further by various other NRC memorarda, which emphasize
the staff's primary responsibility to provide increased direct
inspection and monitoring to assure the safe operation of TMI-1.
In
summary, the TMI-1 Restart Staff was established to substantially
augment the normal NRC resident and regional inspection activities
(1) to provide increased NRC awareness and understanding of the
safety of TMI-1 startup operations, (2) to provide timely NRC staff
response to operational problems or events that may occur during
this period, and (3) to provide a sound technical basis for deter-
mining the effectiveness of licensee management controls for safe
facility operation.
In anticipation of the potential for TMI-1 criticality on June 11,
1985, as permitted by the Commission's Restart Order (CLI-85-09),
the Restart Staff began around-the-clock (24-hour) shift operations
coverage at 3:30 a.m., on June 6, 1985.
The NRC's augmented inspec-
tion program for TMI-1 restart, including planned staffing and.
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Region I
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Di rector
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Region I
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Di rector
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Secretary i
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TMI-l Resident
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Operations . Assessment
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(As Reauired)
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Inseection Staff
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Shift Insoectors
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Plant Operations
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Resident Inspector ( s)
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Resident inspectors
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Startup Testing
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l DRP Project Engineer (s)
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License Examiners
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Project Engineers
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FIGURE 1
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FINAL HEATUP AND SURVEILLANCE TESTING (5 DAYS)
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ZERO AND LOW POWER PHYSICS TESTING (2 DAYS)
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40% POWER TESTING (5 DAYS)
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LOSS OF FEEDWATER
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TURBINE / REACTOR TRIP
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OPERATOR TRAINING AND
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CORRECTIVE MAINTENANCE / MANAGEMENT REVIEW (10 DAYS)
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responsibilities, was discussed by T. E. Murley, NRC Region I
Regional Administrator, during a media briefing at the NRC's
Middletown Office at 10;00 a.m. on June 6, 1985. At 4:21 a.m. on
Junn 7, 1985, one of the reactor coolant pumps was started to
commence the heatup of the reactor coolant system (RCS), and the RCS
temperature reached 200'F at 7:09 a.m. on June 7,1985.
Subsequently, on June 7,1985, the U.S. Court of Appeals for the
Third Circuit in Philadelphia, Pennsylvania, announced its decision
to stay the Commission Restart Order (CLI-85-09). After a determi-
nation by the TMI-1 Restart Staff that the licensee would not be
conducting significant startup testing activities, the 24-hour shift
inspector coverage was terminated at 3:00 p.m. on June 7, 1985.
The
RCS heatup was continued until the plant reached normal hot shutdown
conditions (about 530'F and 2150 psig). The RCS was maintained in
that condition for the remainder of the inspection period to com-
plete licensed operator familiarization training at " hot plant"
conditions, pending further action by the Court of Appeals.
Inspec-
tion coverage was maintained throughout this period by the resident
and support staff components of the Restart Staff.
2.0 Shift Inspection Activities
2.1 Routine Review
As a result of the NRC decision of May 29, 1985, in favor of TMI-1
Restart and in anticipation of an expected June 11, 1985 criticality
date, Region I implemented its augmented inspection coverage as
described in paragraphs 1.1 and 1.2.
The TMI-1 operational assessment staff shift inspectors observed
pre-operational activities to determine the adequacy and effective-
ness of operating personnel performance based on a review of the
indicators listed below:
Operators are attentive and responsive to plant parameters and
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conditions.
Plant evolutions and testing are planned and properly author-
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ized.
Procedures are used and followed as required by plant policy.
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Equipment status changes are appropriately documented and
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communicated to appropriate shift personnel.
The operating conditions of plant equipment are effectively
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monitored, and appropriate corrective action is initiated when
required.
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Backup instrumentation, measurements, and readings are used as
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appropriate when normal instrumentation is found to be defec-
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tive or out of tolerance.
Logkeeping is timely, accurate, and adequately reflects plant
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activities and status.
Operators follow good operating practices in conducting plant
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operations.
Operator knowledge / actions are as a result of performance-
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oriented training.
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Shift inspector findings are addressed below and in paragraph 9.4.
2.2 Valve Lineup Verification
When performing reactor coolant system (RCS) valve lineup verifica-
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tion (dayshift on June 7, 1985) the inspector noticed that Reactor
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Coolant Pump (RCP) 10 No. 1 Seal Leakoff Manual Isolation Valve
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MU-V-960 was shut. With this valve shut, the RCP-10 No. 1 seal
leakoff was isolated.
Continued operation under normal operating
pressure / temperature for an extended period of time with this valve
lineup may result in damage to the seal package, which includes two
other seals. The RCP seal package is important because it forms the
RCS pressure boundary. At the time the lineup verification was
performed, RCP-10 was in operation requiring the pump's seal to be in
operation.
The auxiliary operator who was assisting the inspector in
the valve lineup verification immediately notified the Unit I control
room.
The shift foreman instructed the auxiliary operator to open
MU-V-960. When the valve was open, high range leakoff indication in
the control room increased from 0.7 gpm to approximately 4.25 gpm.
The licensee's Plant Operations Department personnel immediately began
to review this event to determine if any damage had occurred to
RCP-10 seal package.
They documented that review in Plant Incident
Report (PIR) No.1-85-05, dated June 13, 1985.
The pump vendor, Westinghouse, was notified of this event and the
vendor recommended that the plant be cooled down and an inspection
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be performed of the pump's seal package. While the plant was being
cooled down, the No. 2 seal appeared to reseat itself at approxi-
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mately 700 psig.
Because both the No. 1 and No. 2 seals were then
functioning properly, the licensee concluded that there was no
safety concern with the continued operation of RCP-10.
Subsequently,
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the plant was returned to normal hot shutdown operating temperature
and pressure without excessive leakage past the No. 2 seal.
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The licensee's review determined that MU-V-960 was inadvertently left
closed sometime on the previous (midnight) shift on June 7, 1985
after performing seal leakoff flow verification (seal bucket
checks).
This flow verification evolution (which required two valve
manipulations and restoration to normal) was performed by auxiliary
operators under licensed senior reactor operator supervision but with
no specific written procedures.
The involved operators acknowledged
the possibility that they left the valve shut. Operating Procedure
1104-2, " Makeup and Purification System," requires that MU-V-960 be
open during normal operations. Therefore, the inspector considered
this to be contrary to Technical Specification 6.8.1 (289/85-19-01).
The licensee's review also noted that specific guidance had not been
given to the operators regarding proper RCP seal flow verification.
As part of the licensee's own review and corrective action, Procedure
Change Request (PCR) No. 1-05-85-0384 was initiated to add specific
procedural steps to perform " bucket checks" on RCPs.
This PCR is in
the review and approval process.
In addition, the licensee's review noted that the control room
operators had not recognized the problem from information indicated
by the RCP seal leakoff flow recorder in the control room.
The
licensee's review concluded that the control room operators should
have observed and questioned the difference between the low range
leakoff value and the high range leakoff value while starting the
RCPs.
The licensee is making a change to the CR0 log to require
recording of both high and low range flow indications each shift to
help provide additional assurance that operators verify proper seal
flow indication.
The Operations Manager has provided information regarding this
violation and the corrective actions to all shifts to be reviewed by
all crew members.
The inspector reviewed the above corrective actions and concluded
that licensee personnel immediately obtained procedural compliance
and that the licensee had taken adequate corrective measures for
this violation.
2.3 Borated Water Storage Tank Temperature
During the midshift on June 7, 1985, the shift inspector noted a
Borated Water Storage Tank (BWST) high temperature alarm in the
control room.
The inspector questioned the control room operator
about the alarm in regard to meeting a design requirements of
keeping the BWST less than 90*F.
Discussions with the shift supervi-
sor revealed that the BWST heat tracing might be adversely affecting
the adjacent temperature instrument.
The shift supervisor, however,
noted that '.he average temperature indicated by two other BWST
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temperature instruments was less than 90 F.
These instruments
provided input to the plant computer and were not located near the
tank's heat tracing.
The shift inspector referred this matter to the resident inspector
who discussed this item with plant operations and plant engineering
representatives. The inspector noted that the temperature was very
close to the limit and was concerned whether the temperature indica-
tar was giving the operator a true indication of tank temperature.
Based on the inspector's discussions with plant engineering per-
sonnel, the BWST heat tracing temperature was set at 110*F, consis-
tent with the setting on adjacent chemical control tanks.
Sub-
sequently, licensee representatives reset the heat tracing for the
BWST at 50*F.
At this temperature the heat tracing on this tank
would not affect the indication of the tank temperature.
The
resident inspector concluded that BWST temperature at the time of the
observation was in accordance with safety analysis assumptiens and
Technical Specification requirements and considered that the shift
inspector's concern was resolved.
2.4 Summary of Findings
In general, shift inspector observations confirmed that the operators
were attentive to their duties.
They were responsive to symptoms of
abnormal conditions although there was an isolated lapse of atten-
tiveness related to RCP seal leak-off flow indication.
They appro-
priately planned evolutions and they, in general, properly imple-
mented procedures. There was an isolated case of a mispositioned
valve that went unrecognized for over a shift time period but this
was not indicative of a programmatic problem or improper implementa-
tion of the operating system restart valve lineup effort.
The
operators were knowledgeable of plant design and kept themselves
updated on plant activity during each shift.
3.0 _ Plant Operations During Preparation for Star _ tup
3.1 Routino Review
The resident inspectors periodically inspected the facility to
determine the licensee's compliance with general operating require-
ments of Section 6 of the Technical Specifications (TS) in the
following areas:
review of selected plant parameters for abnormal trends;
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plant status from a maintenance / modification viewpoint includ-
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ing plant housekeeping and fire protection measures;
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control of ongoing and special evolutions, including control
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room personnel awareness of these evolutions;
control of documents including log-keeping practices;
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implementation of radiological controls; and,
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implementation of the security plan including access control,
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boundary integrity and badging practices.
The inspectors focused on the following areas:
control rocm operations during regular and backshift hours
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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 selected sections of
other control room daily logs;
areas outside the control room; and,
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selected licensee planning meetings.
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The inspectors identified no conditions adverse to nuclear safety or
inconsistent with regulatory requirements. Additional findings are
noted below.
3.2 partial Emergency Safeguards Actuation
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An unplanned partial actuation of emergency safeguards (ES) compo-
nents occurred at 10:04 a.m. on June 26, 1985 due to personnel
error. While conducting quarterly surveillance testing of reactor
building cooling and Isolation system logic channels, an operator
failed to reset one group of ES components as specified by steps in
the procedure.
This resulted in the unexpected start of the
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emergency diesel generator, makeup pump 1A and decay heat pump 1A,
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and operation of two ES valves (decay heat valve 4A and makeup
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valve 18).
In addition, two fans in the reactor building stopped
due to the ES actuation. The diesel and pumps were secured about
one minute after their initiation and other components were promptly
aligned to their normal operating configurations.
No actual safety
injection resulted, due to the ES valve lineup for the test; all
components functioned as designed; and there was no equipment
damage.
The licensee made proper notifications in accordance with
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Following this occurrence, on June 26, 1985, the inspector reviewed
the plant operations that were in progress and the various personnel
actions that contributed to the unexpected partial ES actuation.
The inspector discussed these matters with the shift foreman and the
cognizant plant engineer (procedure owner) who were both present in
the control room when the surveillance test was being performed.
The inspector considered that the apparent cause of personnel error
was due to several individuals' (control room operator, shift foreman
and cognizant plant engineer) unfamiliarity with the surveillance
test which is required to be performed quarterly during normal plant
operation but was performed only a few times during the previous
years of plant shutdown.
The error apparently was caused, specif-
ically, by the operator's (and others') lack of detailed understanding
of the system response when procedural steps were performed in a
sequence other than that specified by the surveillance procedure.
Also, a communications problem was apparent when the operator
requested, and was too hastily granted, approval for releasing an ES
bypass pushbutton.
However, the consequences (unexpected ES actua-
tion) were obvious to the operator when the error was made.
The
operator response to the initiation was both prompt and correct, and
the remainder of the surveillance test was performed without further
incident.
The inspector observed the shift supervisor relief turnover after
this occurrence and considered the information exchange to be
accurate and thorough as related to the subject event.
The licensee
followup actions to this occurrence were incomplete at the end of
the inspection, in that a 30 day Licensee Event Report (LER) was
being prepared in accordance with 10 CFR 50.73.
This item will
remain unresolved pending NRC review of that report (289/85-LO-01).
3.3 Shif t Supervisor _ Meeting with Plant Management
In preparation for the pending startup, facility management in the
operations and startup testing organization met with shift supervi-
sors on June 4, 1985.
The purpose of the meeting was two-fold:
to
summarize the planned evolutions for the low power physics testing
and power escalation programs; and to discuss with the shift super-
visors cautionary items or lessons learned from other plants which
restarted after long term shutdowns (summarized in an internal
memorandum, dated May 22, 1985, from the Operations and Maintenance
Director,THI-1).
(The review of other plant problems subsequent to
long term shutdown was a Itconsee commitment by letter, dated May 7,
1985, in response to the most recent NRC Systematic Assessment of
Licensoo Performance.) The meeting was also attended by the Direc-
tor, TMI-1.
The NRC's TMI-1 Restart Manager was invited and
attended this meeting.
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Licensee management exhibited initative in conducting the meeting.
It was a frank and open discussion of what was expected of shift
supervisors in terms of overall control of safe operations of the
facility and what shift supervisors could expect of facility manage-
ment in minimizing unnecesary distractions to the overall goal of
safe operation of the facility.
Operations areas or concerns
warranting close attention by the shift supervisors were highlighted
by management along with test sequences that could appear somewhat
complex if not carefully planned by the shift conducting the test.
Various shift supervisors expressed concern over the number of
monitoring organizations who will appear from time to time in the
control room or who are on shif t.
The concern was based on the
groups indirectly demanding excessive attention from shift person-
nel through questioning, discussion, etc.
Licenseo management
reiterated the need for suc5 monitoring, and they required that
management be informed of any interference of shift personnel duties
with respect to the safe operation of the facility.
The inspector had no further comments.
3.4 Summary of Findings
Overall, persornel stationed in the control room exhibited overall
control of daily activities, including problem areas that needed
resolution.
The planning meetings stressed attentiveness to proceed
safely with daily activities, including surveillance and maintenance,
and to resolve any inter-departmental interface problems.
Licensee
upper management and quality assurance department personnel continued
their detailed involvement in site activities.
4.0 Surveillance Testing in_. Preparation for Restart
The inspector reviewed the surveillance test results of selected compo-
nents/ systems to verify that the test procedures were properly approved
and adequately detailed to assure performance of satisfactory surveil-
lance; test instrumentation required by the procedure was calibrated; the
results satisfied Technical Specifications (TS) and procedural acceptance
criteria, or were otherwise properly dispositioned.
The following tests were reviewed:
4.1 Control Rod
4.1.1
Rod _ Drop Time
The rod drop measurement was performed in accordance with
procedure SP 1303-11.1, " Control Rod Drop Time." The
inspector verified by review of the test results performed
on June 9, 1985, that all control rods reached a 75*4
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insertion in less than 1.66 seconds as required by the TS.
The inspector also reviewed several visicorder traces and
verified that the drop time had been interpreted
correctly.
4.1.2
Rod Position Indication
The licensee performed control rod drive (CRO) absolute
(API) and relative position indication (RPI) surveillance
calibration in accordance with procedure SP 1302-5.13,
Revision 6.
Rod position indications were cross checked
among API, RPI and zone reference position.
Deviations
among zone reference position, API and RPI were all within
5% for each rod.
The associated asymmetric rod alarm and
fault were also tested and found acceptable.
4.1.3
Control Rod Program Special Check
The licensee performed control rod exercise in accordance
with procedure SP 1301-9.2, " Control Rod Program Special
Check," on June 9, 1985.
The test results showed that the
rod position indication meter and the corresponding computer
rod position printout correctly responded for each rod
motion. Although the power and instrumentation cables
were not physically checked in this surveillance, the
above test indirectly showed that the cables have been
properly connected.
4.2 Inadequate Core Cooling Monitoring
4.2.1
Saturation Margin Monitor
The inspector reviewed the saturation margin monitor
monthly functional test results (SP 1303-11.52, completed
May 13, 1985).
Test results indicate that the performance
of the saturation margin monitors is in accordance with
applicable TS and restart hearing commitments.
4.2.2
Backup Incore Thermocouple Readout System (BIR0)
_
The BIRO refueling calibration (SP 1302-22) was perfurmed
on August 14, 1984. All thermecouple (T/C) performances
were acceptable except K-12.
The faulty T/C was replaced
by T/C H-13 and a subsequent test performed on March 14,
1985 indicated its acceptance.
The inspector also re-
viewed the recent monthly BIRO T/C check (SP 1302-21).
Test data confirmed that the BIRO's operability was in
accordance with restart hearing commitments.
.
_
.
.
12
4.3 Reactor Coolant System (RCS) Leak Rate
The inspector reviewed the RCS leak rate surveillance (SP 1303-1.1)
results performed on June 8-9, 1985. The surveillance results
indicated that all calculated leakages were well within TS limits.
However, the calculated unidentified leakage was a negative value
from (-) 0.21 to (-) 0.26 gpm which was consistent with previous
surveillance results from (-) 0.21 to (-) 0.29 gpm taken during the
Hot Functional Test during the period April 10-19, 1985. This
anomally was caused by an RCS evaporative loss term that is permitted
to be used by TMI-1 Technical Specifications. The validity of the
l
evaporative loss term (0.27 gpm) has been referred to NRR to determine
'
whether a change to the TS is appropriate (289/84-08-02).
4.4 Reactor Protection System (RPS)
4.4.1
RC Flux Flow
The RPS channels for the reactor DNB protection based on
flow and axial imbalance trip were calibrated in accor-
dance with procedure SP 1302-5.4 on June 5, 1985. The
calibration results for eight flow transmitters
(RC14-A-DPT1 through 4 and RC14-B-DPT1 through 4) and both
RC flow loops (A and B) were found acceptable. The
associated flux / imbalance / flow trip bistables were checked
per SP 1303-4.1, "RPS Functional." The actual gain
adjustment factor for the flow buffer amplifier will be
verified / adjusted when the unit reaches appropriate power
levels.
4.4.2
Reactor Trip on loss of Feedwater (FW)/ Main Turbine Trip
The RPS channels for the reactor trip on loss of FW or main
l
turbine trip were calibrated in accordance with procedure
SP 1302-5.34, " Reactor Trip on Loss of Feedwater/ Main
Turbine Trip," Revision 0.
The instrument loop test data
of May 9, 1984, indicated that the switch setpoint for
pressure switches PS 919 and PS 924 did not meet the
acceptance criteria. Both pressure switches were cali-
brated and retested, and the final values were within the
acceptance criteria of the TS and met commitments made as a
result of the restart hearing.
.
.
.
.
.
_ _ _ _ - _
_ _ _ _ _ .
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13
4.5 Pressurizer Heaters Emergency Power Test
The licensee performed the subject test in accordance with procedure
SP 1303-11.55, " Pressurizer Heaters Emergency Power Functional
Test," Revision 0, on March 20, 1985. This test demonstrated that
1) pressurizer heater groups 8 and 9 transferred from their normal
power bus to the emergency power bus and energized and 2) following
an ES signal the heaters tripped and were not able to be re-applied
while an ES signal was present.
The test results satisfied the
requirement of TS 4.6.3 and restart hearing commitments.
4.6 Other System / Component Testing
'
In addition to the above, various other surveillance test data were
reviewed to ' assure that test results met the TS acceptance criteria.
Approximately 20*4 of the licensee's surveillance procedures were
<
reviewed covering a majority of refueling and annual surveillances,
and selected more-frequent tests. No conditions adverse to nuclear
safety or inconsistent with regulatory requirements were identified.
5.0 TMI-1 Restart License Conditions Review
The inspector conducted a . review and inspection to assure that the
licensee met those continuing and currer.tly applicable (for criticality)
license condifions issued or proposed as a result of or related to the
TMI-I steam generator' repair hearing ~and the restart hearing.
The review
included a verification, as applicable, that an NRC inspection adequately
certified compliance with the Jicense condition.
The inspector verified
that each license condition wa~s met, or the condition was reviewed for
current acceptability to ass'ure that the licensee continued to comply
even with the passage of time due to restart delays.
The license conditions verified based on the review during past inspec-
tions were:
2.C.5 (also see below), 2.C.8(1), 2.C.8(5), Proposed 2.C.9(a),
(b), (1), (m), (n), (r), (t), Proposed 2.C.13(c).
The license conditions
that were verified during this inspection are listed below along with
inspector findings.
5.1 Steam Generator Chemistry Program (LC 2.C.5)
In conjunction with the review of outstanding issues in NUREG 1019,
" Steam Generator Repair Safety Evaluation Report" (and Supplement),
the inspector reviewed the licensee's secondary water chemistry
monitoring program.
The inspector determined that the licensee
program did include a sampling schedule for critical parameters.
The licensee procedures were found to include requirements for
recording and plotting critical parameters.
The program contained -
basic steps to address corrective actions if chemistry parameters
_ _ _ _ _ _ _ _ _ _
.
.
14
4
were determined to be out of specification.
Based on this review of key
procedures, the inspector concluded that the licensee had met
license condition 2.C.S.
Applicable inspections supporting the above noted findings are:
NRC
Inspection Reports 50-289/84-07, 84-16 and 85-17.
5.2 Primary to Secondary Leak Rate Shutdown Limit (LC 2.C.8(2))
The license condition requires that the plant be shut down if primary
to secondary leakage is greater than 0.1 gpm (6 gph) above baseline.
The inspector held discussions with licensee representatives regarding
licensee implementation of the LC issued by Technical Specification
Amendment 103, dated December 21, 1984.
The purpose of these discus-
sions was to ascertain the specific actions by which the licensee
would meet the license condition as described in licensee letter
(Serial No. 5211-85-2070), dated June 8, 1985 and by related OTSG
hearing commitments (Topical Report 008, Revision 3).
The inspector noted that the licensee's procedure (Surveillance
Procedure (SP) 1301-1) lacked specificity of licensee actions upon
an indication of primary to secondary leakage in excess of 6 gph
above baseline (.5 gph) and noted that operations would be permitted
for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with leakage between 6 and 12 gph.
In response, licensee representatives expressed concern about
additional thermal cycles on the primary system, resulting from
unnecessary plant shutdowns caused by a primary to secondary leak
rate indication that may be unrelated to actual leakage because of
transient conditions.
Further, licensee representatives expressed
uncertainty over how the indication of this leak rate would respond
on a day-to-day basis considering measurement inaccuracies, power
level changes or other factors unknown because of noncritical testing.
(The indication of primary to secondary leak rate is a mass balance
calculation between RCS concentration using the Xe-133 isotope as
input to the OTSG and measuring the OTSG output of Xe-133 by way of
the condenser off gas system - a condenser off gas grab sample
provides additional accuracy of primary to secondary leak rate.)
The inspector acknowledged the licensee's concerns and their posi-
tion on the factors affecting the primary to secondary leak rate
calculation.
However, after subsequent discussions, licensee
representatives agreed to re-review the SP 1301-1 procedural actions
after they gained experience and data from the power escalation
program to see if any changes were warranted.
The inspector con-
cluded that the license condition was enforceable as it was stated
.
.
15
and the SP procedural steps were not needed for enforceability.
The
acceptability of the implementing procedure is unresolved pending
completion of licensee action as stated above and subsequent NRC
Region I review (289/85-19-01).
5.3 Liquid Radwaste Separation of Units (Proposed LC 2.C.9.(d))
This proposed license condition requires that isolation of liquid
transfer line interconnections between Units 1 and 2 shall be
maintained. TMI-1 SP 1303-11.48, " Unit 1/ Unit 2 Isolation Verifica-
tion" is used quarterly by the licensee to ensure that all process
piping connecting Unit 1 and Unit 2 liquid radwaste systems is
isolated.
The inspector verified that SP 1303-11.48 was current (June 4,
1985), there were no exceptions or deficiencies, and all signoffs
were complete.
The licensee has satisfied this proposed license
condition.
5.4 Shift Manning Requirements (Proposed LC 2.C.9.(e) through (k))
Theseproposedlicenseconditionsrequirethelicenseetomeei
various minimum staffing requirements, shift rotation, and reporting
requirements (289/82-BC-54).
They are minimum conditions imposed by
the Licensing Board based on the evidentiary record.
The require-
ments of NRC. regulations on shift manning, which in some respects
are more restrictive than these proposed license conditions, are
also applicable.
TMI-1 Administrative Procedure (AP) 1029, " Conduct of Operations,"
Section 5.7 addresses Proposed License Conditions 2.C.9(e) through
(j). TMI-1 Operations Surveillance Procedure OPS-S-286 addresses
Proposed License Condition 2.c.9(k) concerning annual reporting
requirements to the Commonwealth of Pennsylvania and the NRC staff
when insufficient individuals are enrolled in the licensee's train-
ing program. Both of the above procedures were reviewed by the
inspector.
These proposed license conditions have been satisfied.
5.5 Conservative Indication of Saturation Margin (Proposed LC 2.C.9(o))
This proposed license condition requires the TMI-1 emergency proce-
dures to direct operations to rely on redundant saturation indica-
tions that are closest to saturation in determining if the high
pressure injection (HPI) system flow can be throttled until the
backup display system for the incore thermocouples (BIRO) is made
fully safety grade and environmentally qualified (289/83-BC-17).
-
,
.
16
The licensee submitted letters to the NRC staff, dated May 21, 1985
and June 28, 1985, that certify the backup incore thermocouple system
is fully safety grade and environmentally qualified.
Therefore,
this proposed license condition is met.
The qualification of the
BIRO will be further reviewed by NRC Region I to resolve a previous
inspection finding (289/84-06-03).
Abnormal Transient Procedure 1210-10 requires the determination of
saturation margin by conservative indication of redundant saturation
margin monitor instruments (for each RCS loop, used with reactor
coolant pump on) or either of two hand calculation methods.
The hand
calculation methods use either the BIRO or plant computer display of
the five highest incore thermocouples along with safety grade (except
for computer point readout on one pressure channel) RCS pressure
instrument. The inspector noted that, for the RCP off situation, the
most conservative of the hand calculation methods was not specified.
That becomes moot because the licensee certified, subsequent to
inspector questioning, that the BIRO was environmentally qualified
(previous correspondence certified seismic qualifications).
During the review of ATP 1210-10 the inspector noted that the
computer point for pressure instrument 963 was used in the hand
calculation of saturation margin and he further noted that the
instrument string error analysis did not include that computer point
in the 963 instrument loop.
That error analysis was the basis for
staff certification of a TMI-1 Restart Hearing Appeal Board decision
to certify that the instrument error was less than 20 F.
Subsequent
to inspector questioning, licensee representatives performed an
additional analysis and reported that the instrument error was
still less than 20 F.
The inspector concluded that the licensee met
LC 2.C.9(o).
5.6 Interim Measures for Non Safety Grade Emergency Feedwater (Proposed
LC 2.C.9(p))
This proposed license condition requires that an auxiliary operator
be dispatched to the emergency feedwater (EFW) flow control valve
area upon any EFW auto-start condition in order to take manual
control of the valve, if needed; this individual will perform no
other duties until the control room operators verify EFW flow to the
steam generators (289/83-BC-20, previously reviewed and closed).
The inspector reviewed various emergency and alarm procedures.
Within these procedures, various steps relating to EFW initiation
direct the operator to go to Abnormal Transient Operating Guideline
(ATOG) Procedure 1210-10, " Abnormal Transients, Rules, Guides, and
Graphs." Section 2.0 of that Procedure addresses the requirements
of this proposed license condition.
Therefore, this LC is satis-
fied.
___ _
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._
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17
5.7 Emergency Power for Pressurizer Heater (Proposed LC 2.C.9(q))
i
The proposed license condition requires the reactor to be
subcritical or in a hot standby condition prior to connecting the
4
pressurizer heaters to the emergency power supply (289/83-BC-21,
1
previously reviewed and closed).
The inspector again reviewed emergency procedures'1202-2, " Station
Blackout" and 1202-29, " Pressurizer System Failure." Both proce-
i
dures continue to contain guidance to the operators concerning
pressurizer heater connection to the emerger.cy power supply. The
guidance in these procedures satisfies this proposed license condi-
tion.
i
5.8 Restricted Positions and Personnel (Proposed LC 2.C.9(s) and (u))
Proposed License Condition 2.C.9(s) requires that the licensee not
,
'
use TMI-2 pre-accident licensed operators and certain management
personnel in the operations or key management positions of TMI-I as
specified in the Commission Order CLI-85-02, dated February 25,
1985.
In May 1985, NRC Region I management initiated discussions with
,
licensee management regarding their plans to implement this condi-
tion. At the outset of those discussions, it became clear that the
licensee needed to define certain phases or aspects of the condition
based on the hearing record for lack of more specific guidance in
'
The licensee finalized those plans in June 1985 with an
acceptable disposition by the TMI-1 Restart. Staff as noted below.
The licensee initially identified the restricted positions at the
TMI-1 site by marking (yellow highlight) those positions on a May 1,
1985 Organizational Position Listing.
Their bases for identifica-
tion of. restricted positions (in response to the wording of
'
CLI-85-02) included:
licensed operators for TMI-1 including engi-
.
neers and training instructors or other personnel who had licenses
to be maintained; key managers in the operations or training of
operators and those managers in the oversight of operations at the
TMI-1 site; and non-managerial positions involved in the direct
operation or independent oversight of operations at the TMI-1 site.
The inspector identified the following positions as potentially
applicable to the CLI-85-02 restriction which were not included in
the licensee's initial listing:
auxiliary operators, shift techni-
cal advisers, TMI-I QA audit personnel, startup and test manager,
and simulator development :anager.
The licensee representatives
acknowledged the inspector's comments ard incorporated these addi-
tional positions in their restricted position listing.
Also, the licensee identified those preaccident personnel who were
considered to be restricted based on the wording of CLI-85-02.
Their bases for identification were those personnel who filled the
specific positions listed by the restrictions of CLI-85-02 and those
pre-accident licensed TMI-2 operators and trainees on shift. At the
.~
-
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,
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,
18
outset of discussions in this area, licensee representatives
.
'
. expressed uncertainty as to the time period for the term " pre-
accident." Since the license condition had its roots in uncertain-
-
ties about individual performance related to the TMI-2 leak rate
i.
falsification issue, licensee representatives proposed a start time
for the preaccident period as the date of the first RCS leak rate
calculation at TMI-2 (March 22, 1978).
In verbal consultation with
cognizant individuals of the Office of Nuclear Reactor Regulation
Staff, the TMI-1 Restart Staff (1) verified the completeness of the
list of TMI-2 licensed operators in the licensee's listing, and (2)
J
. accepted the licensee's proposed start date for the preaccident
period with respect to identifying those TMI-2 licensed operators and
trainees who potentially were involved in the TMI-2 RCS leak rate
'
falsification.
The TMI-1 Restart Staff also concluded that the
licensee representatives made a reasonable search of records to
identify trainees on shift during the preaccident period (March 22,
1978 to March 28,.1979).
These records were:
training department
records, personnel files, accident generated documents listing
assigned personnel, shift schedules, and legal department records.
The licensee finalized their " confidential" listing of restricted
positions and restricted personnel in a memorandum, (Serial No.
'
5211-85-1254, Revision 1), dated June 20, 1985, from H. Hukill,
Director, TMI-1, to C. Smyth, TMI-1 Licensing Manager. The memoran-
j
dum also required that the Director, TMI-1 will periodically
assure that restricted personnel are not among the TMI-1 licensed
i
operator candidate classes.
The licensee confirmed that this document
will be available for periodic NRC inspections to demonstrate
'
continued compliance with the license condition. As a result of
,
that memorandum, the TMI-1 Restart Staff verified that restricted
'
personnel are not in restricted TMI-1 site organization positions as
defined above. Accordingly, the staff concluded that the licensee
met the restricted personnel condition of CLI-85-02 (proposed LC
2.C.9(s)).
Subsequent to the finalization of licensee implementation plans, two
individuals were identified to the TMI-1 Restart Staff as being in
unique positions.
In one case a restricted individual is presently
a consultant in the training department.
Licensee representatives
,
took the position that this individual was not employed by GPUN at
,
TMI-1, the individual's work received considerable GPUN management
review, and he was not in a restricted position as defined above.
The TMI-1 Restart Staff considered acceptable the licensee's deter-
mination that the individual could continue in that position while
meeting the CLI-85-02 restriction.
i
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.
19
In another case, a former engineer signed an affidavit stating that
he was aware of the CLI-85-02 restriction and that the restriction
was not applicable to him. His basis was that, as a trainee during
the defined preaccident period, he never stood watch in the control
room and was never a part of the operating crew.
Based on the
personal knowledge of TMI-1 Restart Staff inspectors and their
recollection of the individual and his duties, it was considered
acceptable for the licensee not to include this individual in the
list of restricted individuals (also meeting the CLI-85-02 require-
ment of "on shift for training").
With respect to the above, the TMI-1 Restart Staff concluded that
the licensee met proposed LC 2.C.9(s).
Another proposed license condition restricted the two primary
individuals who responded for the licensee to the TMI-2 Accident
Notice of Violation. The above referenced organizational position
listing (May 1, 1985) does not have these individuals listed. Also,
based on the personal knowledge of the TMI-1 Restart Staff inspec-
tors, these individuals are not used to operate TMI-1 or represent
the licensee in TMI-1 matters. Accordingly, the TMI-1 Restart Staff
concluded that the licensee met proposed LC 2.C.9(u).
5:9 Natural Circulation Testing / Training (Proposed LC 2.C.10(a))
The proposed license condition requires, in part, that natural
circulation training be completed prior to exceeding 5% power in
accordance with licensee commitments made in response to TMI Task
Action Plan (TAP) Item I.G.I.
These commitments were made, in part,
in licensee letters, dated May 6, 1981 and April 5, 1983, regarding
the special low power test program and the TMI-1 Restart Test
Specification (Revision 1), respectively.
The inspector discussed licensee implementation plans for the
Natural Circulation Training while below 5% power and reviewed the
approved Lesson Plan No. 11.2.01.281, Revision 0, dated May 23,
1985, " Natural Circulation." Essentially, the licensee plans two
transitions from forced circulation (use of reactor coolant pumps)
along with observation of key parameters (in accordance with Operat-
ing Procedure 1102-16, and Abnormal Transient Procedure 1210-10) and
the recovery from natural circulation. The control room will have
two additional training stations each with a cathode ray tube (CRT)
for display of the RCS pressure-temperature (P-T) plot and one CRT
for parameters display.
Personnel from the training stations will
be rotated to the control panel for actual instrumentation observa-
tion. A training instructor will be at each station and at the
panels guiding the operator through observations pertinent to the
1
indication of natural circulation cooling effectiveness.
1
.
.
20
The inspector noted that the lesson plan was practically oriented
and consistent with the applicable operating procedures.
The
theoretical presentation will be complemented with practical factors
affecting natural circulation cooling. effectiveness such as steam
generator water . level or using emergency feedwater versus normal
The inspector concluded that the licensee is adequately prepared to
.
provide performance oriented training to licensee personnel during
the low power physics test program meeting the related commitments
for TAP I.G.1 and requirements of LC 2.C.10(a).
The inspector acknowledged licensee plans to perform makeup training
after the NRC 5% power hold point for those operators who might be
absent during the low' power physics test program.
The inspector
stated that an NRC staff review would be conducted to assure each
shift (including shift supervisors) was adequately trained on natural
circulation until individual operator makeup training could be
provided later in the power escalation program.
5.10 Previous License Condition Inspection Finding (289/83-14-04)
NRC Inspection Report No. 50-289/83-14 documented the review of
outstanding preoperational and startup testing for various modifica-
tions within the scope of the staff's TMI-1 certification process.
Various tests were keyed to criticality, 5*s power, or completion of
the power escalation program.
The status of those tests is listed
below. Those tests ~ requiring critical and at power conditions were
incorporated as license conditions. The TMI-1 Restart Staff
inspection program will verify the proper completion of all
applicable license conditions as noted above. Accordingly, this
inspector follow item is closed.
The following licensee actions were to be completed prior to reactor
criticality:
Functionally test the emergency feedwater flow indication
--
system and cavitating venturies (TP 233/3 and 233/4 - NRC
Inspections 50-289/84-01 and 84-14) - complete;
--
Functionally test the high pressure injection cross connect and
cavitating venturi modifications (TP 655/1 - NRC Inspections
50-289/84-18, 84-22 and 84-31) - complete; and,
Safety system valve / breaker lineup position verification
--
(various licensee procedures - NRC Inspections 50-289/84-15 and
84-17) - complete.
. _ .
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l
The following licensee actions should be completed prior to exceed-
ing 5% reactor power:
Pressurizer heater emergency power /RCS pressure control func-
--
tional testing (SP 1303-11.55 - NRC Inspection 50-289/83-25) -
complete; and,
--
Functionally test the emergency feedwater backup instrument air
modification (TP 700/2 - Proposed LC 2.C.10(c)).
The following licensee actions should be completed prior to comple-
tion of the power ascension program:
.
Functionally test anticipatory reactor trips on loss of
--
!
feedwater/ turbine trip and automatic initiation of emergency
feedwater modification (TP 800/2, 8, 9 - Proposed LC
,
2.C.10.b.(d), and (f)); and,
--
Implementation of training and power ascension testing per Task
Action Plan Item I.G.1 (Proposed LC 2.C.10(a)).
When the Office of Nuclear Reactor Regulation issues the license amend-
ment which incorporates the above noted " proposed" license conditions,
l
the TMI-1 Restart Staff will determine whether there are any changes to
l
the license conditions that would invalidate this review.
6.0 Loss of Main Feedwater with Actuation of the Steam Leak Rupture Detection
System
l
The purpose of this limited review was to determine the initial antici-
pated response of TMI-I equipment and personnel to a complete loss of
main feedwater to the once through steam generators (OTSGs) with an
inadvertant actuation of the steam leak rupture detection system (SLRDS).
This postulated scenario would be similiar to the event initiation se-
quence that occurred at the Davis-Besse facility on June 9, 1985.
6.1 Areas Inspected
The inspectors reviewed the following documents:
--
TMI-1 Operations Plant Manual;
--
TMI-1 Final Safety Analysis Report;
o
--
TMI-1 Restart Hearing Atomic Safety and Licensing Board Partial
Initial Decision (Plant Design and Procedures and Separation
Issues), Volume 1; and,
,
--
Sequence of Events - Davis-Besse Event of June 9, 1985, and
related documentation.
!
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22
The following procedures were reviewed by the inspectors:
--
Abnormal Transient Operating Guidelines (ATOG) (ATP) 1210
Series;
--
Loss of Feed to One Steam Generator, EP 1202-26, Revision 10;
and,
Total Loss of ICS/NNI Power, EP 1202-40, Revision 5.
--
The following piping and instrument drawings were reviewed by the
inspectors:
--
C-302-081, Revision 25, Feedwater;
C-302-011, Revision 26, Main Steam; and,
--
C302-082, Revision 3, Emergency Feedwater.
--
The following elementary electric diagrams were reviewed by the
inspectors:
--
SS-208-110, Revision 9, 6900 V Switchgear 1A2;
--
SS-208-105, Revision 0, 6900 V Switchgear;
--
SS-209-755, Revision 4, DC and Miscellaneous;
SS-209-756, Revision 4, DC and Miscellaneous;
--
SS-208-421, Revision 6, 480 V Control Center;
--
--
SS-209-143, Revision 7, DC and Miscellaneous;
--
SS-209-144, Revision 6, DC and Miscellaneous;
--
SS-208-425, Revision 6, 480 V Control Center; and,
--
SS-208-524, Revision 1, 480 V Control Center.
In addition to the above reviews, the inspectors had discussions
with various licensee representatives.
The inspectors physically walked down the EFW system to determine if
there were any deficiencies present. One issue was raised by the
inspectors as a result of this walk down.
It concerned preventive
maintenance (PM) on the EFW system strainers and check valves.
The
inspectors determined that the strainers had been removed and PM was
conducted on the check valves. The inspectors reviewed the Pump and
.
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23
Valve Inservice Testins sIST) Program and determined that all the
check valves were periodically tested to provide assurance of the
operability of these valves during their service life.
6.2 Expected Sequence of Events
Assuming all Technical Specification safety related equipment was
operable including the emergency feedwater system with the reactor
at 100?s power, the inspector postulated a sequential loss of main
feedwater pumps (MFP) with a subsequent (but unrelated) actuation of
the steam line rupture detection system.
Due to the loss of one MFP
an automatic power runback would occur due to the integrated control
system control logic.
The power reduction might cause RCS TAVE to
rise thereby causing pressurizer level and subsequently RCS pressure
to rise to the reactor trip setpoint. A challenge to the PORV may
occur depending on plant-specific conditions.
Subsequently the
second MFP is lost (reason unknown).
(This delayed loss of
feedwater is conservative since the complete loss of MFP causes a
reactor trip due to pressure switch in the MFP turbine hydraulic
system, installed as a result of the TMI-1 restart hearing.) The
complete loss of MFP not only initiates a reactor trip but it also
initiates emergency feedwater (EFW) due to differential pressure
switches scensing across the MFP.
The applicable operating / emergency
procedures guide the operators to feed both OTSG's and assure adequate
primary to secondary heat transfer for reactor core cooling.
Since
EFW initiated due to the loss of MFW, control of the feedwater
regulating valves, EF-V30A/B, is automatic to 30" on the startup
range.
Further, by proposed license conditions, existing procedures
require that an auxiliary operator be dispatched to the EF-V30's to
take manual control as directed by the control room if safety grade
flow instrumentation indicates a loss of EFW.
'
Both 50?4 capacity (but each sufficient for post accident decay heat
loads) safety grade motor driven emergency feedwater pumps (EFPs)
and one 100*6 capacity turbine driven (non-safety grade) EFP will
receive the auto-start signals. To produce this signal, the actua-
tion system is arranged into two trains.
Each train contains two
control grade differential pressure switches (one for each MFP) or
sensors indicating a loss of all reactor coolant pumps. This circuit
is designed so that a single failure will not prevent the EFW
system from functioning.
If, for an unknown reason, the turbine
driven EFP would trip due to an overspeed condition, each motor
driven EFP would provide enough feedwater to an OTSG.
The EFW control valves fail open on the unlikely loss of all instru-
ment air (backed up by a safety grade two hour passive air bottle
I
arrangement).
Loss of ICS power to EF-V30A/B is backed up by a safety
grade automatic controller.
If in the unlikely event that the EF-V30's
L
l
t
. -
-
_ _ - -
- ._.
.
-
.
-
.
-
_-
-.
,
.
24
stick closed, recent modifications (for the long term upgrade of
EFW) provide for a mechanical (operator local control) bypass around
the EF-30's until the Cycle 6 (refueling after restart) startup.
Abnormally low water levels in the OTSGs should not occur but if it
does there is no isolation of the main steam isolation valve or EFW
flow control valve.
(No EFW discharge isolation valves exist except
for flow check valves.) The steam line rupture detection system
(SLRDS) responds only from low pressures (less than 600 psig) in
pairs of steam line piping and actuation affects only main feedwater
to the affected (ruptured) OTSG.
(The isolation of EFW by SLRDS was
removed as a result of the TMI-1 restart hearing.)
In case emergency feedwater is unavailable (beyond design basis
event) the high pressure injection (HPI) system (makeup pump to RCS)
is required by procedure to be used in a feed and bleed cooling
mode.
The HPI pumps have a shutoff head above maximum systen
operating pressure.
6.3 Conclusion
Based on this limited review, the inspector concluded that the
present design of TMI-1 would preclude a serious abnormal event
occurring from a loss of all main feedwater with a spurious SLRDS
actuation.
First, actuation of the SLRDS merely isolates main
feedwater, not emergency feedwater.
Second, the EFW system is
diverse and comprised of two safety grade motor driven pumps and one
turbine driven pump.
Third, recent EFW system modifications provide
two separate alternate paths of emergency feedwater into each OTSG
if the standard paths are unavailable; this lineup would have to be
accomplished by local manual action until after the next refueling
outage.
Finally, the HPI system is capable of supplying water to the
reactor for a feed and bleed mode of cooling if emergency feedwater
was not available.
The HPI pump shutoff head is above maximum system
operating pressure.
7.0 Corporate Inspection
During this inspection, the resident inspector conducted an inspection at
the licensee's corporate office (Parsippany, New Jersey) to follow up on
specific outstanding issues.
7.1 Allegation Regarding Vendor Surveillance Representative
On November 21, 1984, the Director of Quality Assurance reported to
the resident inspector that the licensee received a second allegation
concerning a vendor surveillance representative. The allegation,
similar to the allegation documented in NRC Inspection Report 50-289/
84-33, was received from a vendor representative.
It was alleged
.
. _ _ _ _ _ - _ . -___ _ _
_
_
_
_.
-_
_
-
'
.
.
- -
25
.
that the same vendor surveillance representative offered to perform
,
consulting and contract services for the vendor for personal gain.
The licensee initiated another investigation to address the recent
allegation.
The inspector reviewed the documentation associated with the investiga-
tion.
The allegation by the vendor was made orally in casual
passing to a GPUNC auditor.
The vendor characterized the allegation
,
as one individual's word against another individual's word and
^
not worth pursuing.
Because the vendor did not desire to pursue the
3
allegation, the allegation could not be fully substantiated.
However,
the licensee's investigation included a telephonic contact of all
vendors that the licensee's vendor surveillance representative had
,
audited during the period in question.
The licensee's investigation did not uncover any more alleged
improperties by the vendor surveillance representative.
However,
licensee management d?cided to reassign the individual for various
performance-related reasons to another position which does not
require auditing of vendors.
In addition, the inspector reviewed corporate procedure
1000-POL-1010.2, Revision 0, effective November 15, 1982, " Code of
Business and Conflict of Interest Statement," with the Director of
Quality Assurance and other key managers. The procedure requires
certain GPUN employees to sign a statement revealing any outside
interests that would conflict with GPUN corporate objectives.
Prior
y
to this time, vendor surveillance representatives were not required
' , ~
to sign this statement.
Through dicussions with licensee represen-
tatives and a review of selected records, the inspector determined
that vendor surveillance representatives are now required to sign
the " Conflict of Interest Statement," as commited to by a licensee
representative in NRC Inspection Report 50-289/84-33.
Based on the above review, the inspector concluded that there were no
nuclear safety implications or conditions adverse to quality.
7.2 Fire Protection Modification Preliminary Engineering Design Review
(PEDR)
As part of a continued review of licensee's activities in the area
of Plant Modificaticns, the inspector attended a Preliminary
..
4
.
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. . . , . .
,_-_
.
, - . -
-
,
. .
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.-
,
.
26
Engineering Design Review (PEDR) Meeting on 10 CFR 50, Appendix R
(Fire Protection Modification). The PEDR reviewed their vendor's
evaluation on overall approach to Appendix R compliance.
The TMI-I Appendix R evaluations being performed by Gilbert / Common-
wealth have been consolidated into a single report entitled "Appen-
dix R Circuit Evaluation Summary Report." This report includes a
presentation of the level of fire protection required for compliance
with 10 CFR 50, Appendix R, selection of systems and components
required, evaluation of required circuits, and development of
proposed modifications.
The sections. dealing with the above sub-
jects provide an overview of the approach to meeting 10 CFR 50,
Appendix R at TMI-1. Most of this work is scheduled to be performed
during the next refueling outage.
The meeting was held at the GPU Corporate Office and was attended by
representatives from corporate engineering, maintenance and
construction, licensing, plant engineering and representatives from
Gilbert / Commonwealth.
(Since plant operations representatives were
unable to attend, the PEDR will be continued at a later date to
obtain operations department comments.) During this portion of the
PEDR, the project engineer presented the work on a system by system
basis.
This portion of the PEDR appeared to address all aspects of
the modifications from the regulatory requirements viewpoint.
The
inspector noted that the meeting demonstrated that there was still a
significant amount of work to be done during cycle 6 refueling as
well as some more engineering work.
In general, the inspector considered the PEDR to be a useful mechan-
ism to identify problems encountered during modification installa-
tion.
8.0 Diesel Generator Interpolar Connecting Strap Failure (Part 21 Report)
8.1 Background
The 10 CFR 21 report, dated June 3, 1985, by the Louis Allis Company
describes the failure of one interpolar connector in an emergency
diesel generator at the Calvert Cliffs Nuclear Station.
Region
based inspectors reviewed licensee corrective actions at Calvert
Cliffs Nuclear Station on June 6, 1985, as documented in reports
50-317/85-13 and 50-318/85-11. The 10 CFR 21 report identifies
TMI-1 as having two diesel generators (Colt order #205672) with
interpolar connectors.
Figure 3 (attached) is a sketch of the
TMI-Calvert Cliffs interpolar connector area and shows the signifi-
cant fatigue cracking found on the Calvert Cliffs diesel genera-
tor.
9
P
.
Laminated Iron
/
Pole Plate
l
Interpolar
Connedting Strap (Cu)
Catastrophic
.
Fatigue
Crack
,. :
Location
',<y
,e '
. . -
Bar (Cu)
Shorting
/
, , . .
Strap (Cu)
("'
g
'
j
f
.
<
,
/
Braze '
Cracked through Near Center
of Length on Eight Straps
at Calvert Cliffs
Structural
Bar
Diesel Generator Alternator
(Am6rtisseurWinding)
.
FIGURE 3
_
_
_
.-
-
.
. _ _
. - _ .
_
_
- _ _ - . _ - .
.
W
.
27
'
8.2 Field Observations
On June 7, 1985 the same two region based inspectors reviewed
licensee corrective actions for the diesel generators at TMI-1. The
.
'
review included the method of strap removal, condition of the straps
with respect to fatigue cracking, and the licensee's evaluation of
,
potential electrical effects of strap removal.
Inspector observa-
4
tions included portions of the strap removal process, associated
quality control inspection, liquid penetrant testing and the result-
ing generator conditions.
The TMI-1 maintenance procedure for job ticket CG908 provided
details for removal of the interpolar straps including protection
,
from chips or filings and it provided for post maintenance testing
which included vibration analysis and normal Technical Specification
i
surveillance testing. The procedure provided for a cut location that
would leave a maximum stub, 1/2" long.
The inspector reviewed the
t
Calvert Cliffs fatigue crack location (as noted on Figure 3) on the
shorting strap with the TMI-1 preventive maintenance manager. As a
result, the licensee concluded that the stub length of the shorting
straps on generator "A" should be cut as close as possible to the
pole plate.
The inspector later observed cuts made to remove connecting straps
from generator "A" and noted the cut position to be properly located
to not leave a stub.
Followup of this concern by the resident inspector on June 12, 1985
resulted in the observation that the stubs previously remaining on
generator "B" were removed.
The interpolar connecting straps, as-removed from generator "B",
were examined by the inspector and found to not have midlength
cracking. The same observation, as confirmed by liquid penetrant
examination was made by licensee QC inspection personnel on straps
from generator "A".
The liquid penetrant examination report of June
4
L
10, 1985 for generator "A"
showed the general presence of weld
discontinuities, two cracked areas on the shorting straps and one
crack near the centerline of the weld.
However, the inspector
>
concluded that significant fatigue cracking, similar to that of the
Calvert Cliffs interpolar connecting straps, did not occur on the
TMI-1 straps although some cracking had initiated.
The TMI-1
maintenance actions provided for prevention of future fatigue
cracking in this area by removal of the interconnecting straps and
shorting strap stubs.
No conditions adverse to nuclear safety or inconsistent with regula-
tory requirements were identified.
i
,
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28
8.3 Electrical Engineering Evaluation
The inspector reviewed the licensee's engineering evaluation on the
effect, if any, of removing the interpolar connecting straps linking
the damper windings on the two emergency diesel generators, EG-Y-IA
and EG-Y-IB at the facility. The information considered by the
licensee evaluation included correspondence from the generator
manufacturer (Louis Allis letter to Colt Industries, Fairbanks Morse
Engine Division, dated June 3,1985) anc' the engineering evaluation
done at Calvert Cliffs, (Facility Change Request (FCR) 85-1025,
dated May 26, 1985).
The inspector reviewed these evaluations and concurred with these
licensees, after subsequent discussions with the generator manufac-
turer, that the removal of the interpolar connecting straps will
have no measurable affect on voltage and frequency regulation when
accepting or dropping loads.
Further, no changes involving relay
coordination were warranted. Additionally, the inspector concluded
that the removal of these interpolar connecting straps slightly
changed (increased) the negative sequence reactance and the
quadrature substransient reactance which would result in reduced
fault current for an unbalanced three phase load.
The connecting
straps make the damper winding circuitry continuous by shorting the
damper bars on the field pole faces from one pole to the next. This
arrangement is advantageous when synchronous generators of dissimilar
sizes are run in parallel; a mode that dnes not occur at TMI because
it would constitute a violation of Technical Specification require-
ments.
The inspector reviewed the data obtained from the Diesel Generator
Surveillance Procedure 1303-4.16, Revision 31, dated May 7, 1985,
and the Preventive Maintenance Procedure E-1 " Vibration Analysis for
Rotating Equipment," Revision 4, dated July 4,1981, subsequent to
the removal of the connecting straps to assure the generators
performed their intended functions satisfactorily.
No conditions adverse to nuclear safety or inconsistent with regula-
tory requirements were identified.
8.4 Conclusion
The inspectors concluded that GPUN had adequately evaluated the
effects of the removal of the interpolar connecting straps and took
appropriate followup action. The licensee was responsive to the
vendor supplied information and NRC identified concerns.
Based on
operating history of 14 similar diesels without the interpolar
connectors, the review of the licensee-identified factors involved
in this issue, input from the manufacturer, and observations of the
inspectors, the licensee satisfactorily completed preventive /
corrective actions (289/85-PT-01).
This completes the review
of the subject Part 21 report at TMI-1.
'
e
.
29
9.0 Restart Readiness
During the inspection, the resident inspectors assisted by region based
inspectors continued the review of equipment (started in NRC Inspection
No. 50-289/85-12) in selected areas to assess the readiness of the plant
for startup.
The selected areas inspected included safety related build-
ing spaces; outstanding licensee identified items in the surveillance,
maintenance and modification areas; outstanding NRC inspection findings;
and selected valve lineups.
The objective was to identify equipment
operability problems that could adversely affect safe operation of the
facility.
The results of this review are documented below.
9.1 Safety Related Building Spaces
Periodically, the inspector reviewed safety related building spaces
to identify any loose equipment, scaffolding, or other problems such
as fire hazards / housekeeping that could adversely affect the opera-
bility of safety related equipment in adjacent areas. The inspec-
tion also included a review of the following procedures and internal
correspondence which provide administrative control of such miscel-
laneous equipment stored in safety related areas.
--
Maintenance Procedure (MP) 1401-18, Revision 0, June 3, 1985,
Equipment Storage Inside Class 1 Buildings
MP 1440-Y-3, Revision 1, February 25, 1985, Scaffold Inspection
--
--
Inter-office Memorandum (Serial No. 3300-85-130), June 21,
1985, from the Manager Plant Engineering to Operations and
Maintenance Director, " Scaffolding Remaining Inside Class 1
Buildings During Plant Power Operations."
Selected areas of the following safety related buildings were in-
spected:
reactor building; auxiliary building; fuel handling
building; intermediate building; diesel generator building; and
control building.
In general, equipment storage was satisfactory and in accordance
with the above referenced procedures and memorandum. However, at
the beginning of the inspection period, the inspector identified
some areas of concern with respect to loose equipment on rollers,
loose scaffolding and loose floor grating. At that time, the
licensee was in the process of correcting these known deficiencies
in preparation for the pending June 11, 1985 criticality date.
._ _
, - .
.
30
Mechanical Engineering was in control of assuring that stored
equipment was properly tied down and residual scaffolding to remain
in place whs identified and restrained to criteria established by the
licensee.
~
Unrestrained equipment without rollers was located and positioned on
the floor at a safe distance to not adversely affect safety related
equipment if it fell over.
Equipment on rollers was restrained with
wire rope. Scaffolding was rigid and restrained to the building
walls using wire rope and cement anchors.
Loose equipment on top of
platforms or brackets was minimized and were assumed to fall and
therefore kept at a safe distance from the safety related equipment.
Fire protection engineers were actively involved in analyzing
adverse fire hazard loadings in safety related areas due to scaf-
folding platforms. There were no adverse conditions in building
spaces with respect to stored equipment or housekeeping.
As of June 28, 1985 there were no conditions adverse to nuclear
safety.
9.2 Outstanding Licensee Identified Items
The inspector reviewed selected portions of the licensee's appli-
cable corrective action tracking systems to determine if any adverse
condition for safety related equipment operability existed.
The
inspector's review included tracking systems for open maintenance
job tickets, open exceptions and deficiencies (E&Ds) associated with
technical specification surveillances, and open plant modification
incomplete work list items.
The inspector reviewed the open job tickets and discussed all work
that had been classified as priority one, two and three. At the
completion of the review, only one job was classified as priority
one.
This job remained open only due to administrative closecut of
associated paperwork. Of the priority two and three work, the
inspector determined that the work required by these jobs would not
have an adverse affect on the plant safety if not performed prior to
returning the plant to operations.
The inspector reviewed approximately 20% of the technical specifica-
tion surveillances to ensure that the required test was performed
within the proper frequency and that test data obtained met the
procedures acceptance criteria.
In addition, the inspector reviewed
all E&Ds noted by the licensee for all current surveillances.
From
this sampling the inspector determined that the licensee was properly
conducting required surveillances and none of the noted deficiencies
or exceptions would adversely affect plant safety.
.
,
.
31
This review identified approximately 25 of 60 E&Ds outstanding
because'of needed_ procedure changes.
The inspector questioned
licensee representatives as to why so many procedure changes were
needed since the surveillance program has been implemented during the
long term shutdown.
In response, licensee personnel characterized
the changes as improvements or typographical error corrections not
affecting TS acceptance criteria or operability. Based on a limited
review, the inspector confirmed the licensee representatives' state-
ments.
The need for surveillance procedural improvements will
continue to be routinely reviewed by NRC Region I.
The incomplete work items list (IWL) was reviewed. The inspector
discussed the IWL with licensee representatives.
The licensee
adequately resolved or addressed each item on the IWL to ensure that
no adverse condition would exist due to an item remaining open. The
inspector also discussed with the licensee how or if modifications
would continue if the plant restarted.
The licensee stated the
number of modifications during plant operations would be limited.
For the control room and the reactor building, the licensee stated
that no modification work would be performed unless specifically
authorized by plant management.
The inspector found no condition that would adversely affect plant
safety in these areas.
9.3 Outstanding Inspection Findings
In conjunction with a licensee representative, the inspector re-
viewed the Region I file of outstanding inspection findings to
identify any equipment operability problems adversely affecting safe
operation of the facility.
The licensee representative identified
those items ready for review or tentative dates when items would be
ready for review.
No conditions adverse to nuclear safety were
identified.
.
9.4 Valve Lineup Verifications
As-part of the validation of the TMI-1 readiness for restart, the
NRC TMI-1 Restart Staff independently verified the position of
,
l
safety-related valves. The shift inspectors, with the aid of
auxiliary operators, verified the position of valves listed in the
'
following operating procedures:-
l
Operating Procedure (0P) 1104-1, Core Flood System;
--
OP 1104-2, Makeup and Purification;
--
,
OP 1104-4, Decay Heat Removal System;
--
4
l
OP 1104-5, Reactor Building Spray; and,
--
I
I
.
-
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,
32
OP 1101-3, Containment Integrity and Access Limits.
--
In general, the valve lists were determined to be accurate and
valves checked were in their proper position.
However, MU-V-950 was
found mispositioned, as discussed in section 2.0 of this report.
Due to the continued delay of restart (U.S. Court of Appeals for the
Third Circuit stay of the Commissions restart decision), this effort
was stopped but the review would normally include additional safety
related systems.
No conditions were identified that would preclude safe operation of
the facility.
10.0 TMI-1 Replica Simulator
Region I staff reviewed the concerns described in a letter, dated April
5,1985 from Mrs. Marjorie M. Aamodt to the Chairman, Atomic Safety and
Licensing Board, regarding alleged design problems with the training
simulator (TMI-I Replica Simulator) being installed at TMI-1.
The letter
indicated that the capabilities of the simulator have been undermined as
a result of some decisions by GPUN management in opposition to the advice
of engineers assigned to the project.
The letter also stated that Mrs.
Aamodt had the name of an engineer who resigned because of these deci-
sions.
Subsequent to staff discussions with Mrs. Aamodt, the wife of the engi-
neer was contacted.
She indicated that her husband (the subject engi-
neer) was unavailable for two to three months because of travel. The
information the wife provided was somewhat different from the information
provided by Mrs. Aamodt in her letter.
For example, the wife indicated
that:
her husband's decision to leave GPUN employment was totally for
--
personal reasons;
--
her husband's feeling was that GPUN was doing a good job on the
simulator project; and,
--
she believes the contrasting information may have came from a next
door neighbor.
Region I intends to discuss this matter with the engineer when he is
available in two or three months.
This area is unresolved pending NRC staff discussions with the former
GPUN engineer (289/85-19-02).
,
. _ - . . - .
-
-
- - - - -
-
, - . -
._
_
.-
-
-
_ . -
_
,. .
.
33
a
j
11.0 Follow-Up on Previous Inspection Findings
.
The following items were reviewed to assure that the licensee took
l
adequate corrective action in a timely manner and/or met their commit-
ments as stated in applicable inspection reports.
4
11.1 (Closed) Inspector Follow Item (289/82-BC-01 through 06): NRC
Region I staff to review for adequacy hot functional test procedures
(TP 600 series and below) low physics test procedures (TP 700
series) and power esculation test procedures (TP 800 series) and
'
related licensee test results evaluation.
i
The review of the preoperational (up to hot functional testing) test
4
procedures and test results evaluation was completed as documented
in NRC Inspection Report 50-289/85-16.
The review for technical
adequacy of the TP 700 and TP 800 series procedures was intially
+
completed as documented by NRC Inspection Reports 50-289/84-01,
84-06 and 84-14. A re-review of the current revisions of these
procedures was completed in Inspection Report 50-289/85-18.
Imple-
mentation of these test procedures along with a review of licensee
i
test result evaluations will be followed as a part of the TMI-1
l
Restart Staff' inspection program and specific inspection plans.
.
11.2 (Closed) Inspector Follow Item (289/82-BC-54, 61, 63 and 83-BC-17
j
and 83-14-04):
Specific licensee conditions to be incorporated into
the TMI-1 Restart Hearing License Amendment.
Detailed review of all applicable and proposed license conditions is
documented in paragraph 5.0.
r
11.3 (Closed) Inspector Follow Item (289/83-BC-15):
Restart License
,
Condition on Probation Period for Licensee's Training Qualification
[
,
and Requalification Test Program.
This proposed license condition (2.C.12) subjects the licensee's
training program to an in depth audit by independent auditors ap-
)
proved by the Director of the Office of Nuclear Reactor Regulation
'
(NRR).
By letters, dated October 1, 1982 and May 3, 1983, the
licensee provided NRR information related to the qualification of
.
their proposed auditor (Data Design Laboratories, Inc. (DDL)). By
E
letter, dated April 9, 1984, the Director of NRR approved DDL as the
board mandated independent auditor.
In accordance with this licensee
,
'
condition, the probationary period was to last two years after
'
- restart of the unit. The work of the auditor will be subject to
further NRR review.
In response to Board concerns that generated this proposed licensee
condition, Region I continued to conduct licensed and non-licensed
i
training inspections on at least an annual basis and in some cases
more frequently supplemented by special reviews such as the Operator
.
5
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.
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'
34
,
Readiness Inspection (50-289/84-05).
The resident inspectors have
l
periodically factored these concerns into their routine inspections.
'
The planned shift inspector coverage is oriented toward looking at
operator performance that is a result of performance oriented
,
training.
This inspection coverage (except the shift assignments)
will continue during the two year probation period.
In summary, the licensee properly implemented commitments made and license
conditions existing or proposed as a result of the TMI-1 restart hearing.
12.0 Exit Interview
.
The inspectors discussed the inspection scope and findings with licensee
management at the exit interviews conducted on June 7 and June 28, 1985.
The following licensee personnel attended the final exit meeting:
J. Colitz, Plant Engineering Director, TMI-l
--
T. Dunn, Quality Assurance / Operations /Radiologia1 Control Supervisor
--
H. Hukill, Director of TMI-1
--
C. Incorvati, GPUN, TMI Audits Supervisor
--
R. Neidig, TMI-1 Communications
--
C. Smyth, TMI-1 Licensing Manager
--
R. Toole, Operations & Maintenance Director, TMI-I
--
As discussed at the meeting, the inspection results are summarized in the
.
cover page of the inspection report.
The licensee representatives
indicated that none of the subject matter discussed contained proprietary
information. With the issuance of a licensee letter certifying the
,
safety grade qualification of the BIRO system, the inspector noted that
there were no obstacles (physical or administrative) to the safe restart
of the unit.
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 3.2, 5.2 and 10.0.
Inspector Follow Items are matters which were established to administra-
tively follow open issues based on licensee or staff commitments frem the
TMI-1 restart hearing.
Inspector follow item (s), discussed during the
exit meeting, are documented in paragraphs 5.0 and 11.0.
t
.. *
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-289/85-19
Docket No.
50-289
.
License No.
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:
May 31, 1985 - June 28, 1985
Inspectors:
N. Blumberg, Lead Reactor Engineer, Region I
J. Bryant, Senior Resident Inspector (Oconee), Region II
B. Burgess, Project Inspector, Region III
E. Gray, Lead Reactor Engineer, Region I
0. Haverkamp, Technical Assistant for TMI-1 Restart,
Region I
- T. Peebles, Senior Resident Inspector (Turkey Point),
Region II
M. Schaeffer, Reactor Engineer, Region I
R. Urban, Reactor Engineer, Region I
P. Wen, Reactor Engineer, 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 familiariza-
tion training and facility orientation.
Approved By:
Aw
7/r7 /Y
h
[R. Conte,TMI-1RestaQManager
Date
TMI-1 Restart Staff
Division of Reactor Projects