ML20137D506
| ML20137D506 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 01/09/1986 |
| From: | Kane W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | Jun Lee AFFILIATION NOT ASSIGNED |
| Shared Package | |
| ML20137D512 | List: |
| References | |
| NUDOCS 8601170015 | |
| Download: ML20137D506 (4) | |
See also: IR 05000289/1985025
Text
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UNITED STATES
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January 9,1986
Ms. Jane Lee
183 Valley Road
Etters, PA 17319
Dear Ms. Lee:
This is in response to your letter of October 22, 1985, to Commissioner
Asselstine in which you asked several questions related to Three Mile Island
Unit 1 (TMI-1) and made several comments related to TMI-2.
You requested a report on each of the pipe breaks and subsequent releases
reported by General Public Utilities (GPU) on October 22, 1985. Specifically,
you asked which pipes were broken, what was the condition of the steam tubes,
and exactly how much radiation was released.
The repairs to the leaks referred to in the GPU press release were associated
with lines external to the steam generators and were located inside the
reactor building. One of the leaks was located in a bolted flange connection
on an emergency spray ring header and the other was located in a valve body-
to-bonnet bolted connection on a steam generator level transmitter isolation
valve. Both of these leaks were temporarily repaired as discussed in NRC
Inspection Report 50-289/85-25, which was issued on November 29, 1985. A copy
of that report is enclosed. Small leaks of several drops per minute were
observed again at these same locations on January 2, 1985, and were again
temporarily repaired. Permanent repairs are scheduled during the required
steam generator inspection outage currently scheduled for March 1986. The
leaks were inside containment and there was no release to the environment.
William D. Travers, Director of the TMI-2 Cleanup Project Directorate, Office
of Nuclear Reactor Regulation, has reviewed your comments related to the refer-
enced memorandum from W. D. Travers to T. A. Rehm, dated September 25, 1985.
While acknowledging your continuing concern, the staff maintains the information
contained in the referenced memorandum, which responded to your September 24,
1985 request to Commissioner Asselstine, is accurate. In addition to reiterating
the concerns expressed in your September 24, 1985 letter, you noted that you
had made several attempts to obtain information on the disposal of charcoal
filters removed from TMI-2 in April 1979. We are unaware of any requests
directed to the NRC staff for such information. Dr. Travers has informed me
that he will obtain this information and send it directly to you.
Sincerely,
" f(v /
W liiam F./Kane, Director
TMI-1 Restart Staf f
Enclosure: As stated
9601170015 860109 ,
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Ms. Jane Lee 2
Distribution:
A 001245
H. Denton, NRR
D. Eisenhut, NRR
T. Rehm, EDO
W. Travers, NRR
T. Murley, RI
R. Starostecki, RI
W. Kane, RI
R. Conte, RI
Pubile Docuinent Room (PDR)
Local Public Document Room (LPDR)
Region I Docket Room
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.
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I
January 9, 1986
Hs. Jane Lee
183 Valley Road
Etters, PA 17319
Dear Ms. Lee:
This is in response to your letter of October 22, 1985, to Commissioner
Asselstine in which you asked several questions related to Three Mile Island
Unit 1 (TMI-1) and made several comments related to TMI-2.
You requested a report on each of the pipe breaks and subsequent releases
reported by General Public Utilities (GPU) on October 22, 1985. Specifically,
you asked which pipes were broken, what was the condition of the steam tubes,
and exactly how much radiation was released.
The repairs to the leaks referred to in the GPU press release were associated
with lines external to the steam generators and were located inside the
reactor building. One of the leaks was located in a bolted flange connection
on an emergency spray ring header and the other was located in a valve body-
to-bonnet bolted connection on a steam generator level transmitter isolation
valve. Both of these leaks were temporarily repaired as discussed in NRC
Inspection Report 50-289/85-25, which was issued on November 29, 1985. A copy
of that report is enclosed. Small leaks of several drops per minute were
observed again at these same locations on January 2, 1985, and were again
temporarily repaired. Permanent repairs are scheduled during the required
steam generator inspection outage currently scheduled for March 1986. The
leaks were inside containment and there was no release to the environment.
William D. Travers, Director of the TMI-2 Cleanup Project Directorate, Office
of Nuclear Reactor Regulation, has reviewed your comments related to the refer-
enced memorandum from W. D. Travers to T. A. Rehm, dated September 25, 1985.
While acknowledging your continuing concern, the staff maintains the information
contained in the referenced memorandum, which responded to your September 24,
1985 request to Commissioner Asselstine, is accurate. In addition to reiterating
the concerns expressed in your September 24, 1985 letter, you noted that you
had made several attempts to obtain information on the disposal of charcoal
filters removed from TMI-2 in April 1979. We are unaware of any requests
directed to the NRC staff for such information. Dr. Travers has informed me
that he will obtain this information and send it directly to you.
Sincerely,
William F. Kane, Director
THI-1 Restart Staff
Enclosure: As stated
1
o
Ms. Jane Lee 2
Distribution:
EDO 001245
H. Denton, NRR
D. Eisenhut, NRR
T. Rehm, EDO
W. Travers, NRR
T. Murley, RI
R. Starosteckt, RI
W. Kane, RI
R. Conte, RI
Pubite Document Room (PDR)
Local Public Document Room (LPDR)
Region I Docket Room
TMICPD RI:I
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- NUCLEAR REGULATORY COMMISSION
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Docket / License No. 50-289/DPR-50
GPU Nuclear Corporation
ATTN: Mr. H. D. Hukill
Director, TMI-1
P.O. Box 480
Middletown, Pennsylvania 17057
Gentlemen:
Subject: Inspection 50-289/85-25
During the period from October 18-25, 1985. members of the NRC TMI-1 Restart
Staff conducted routine and special safety inspections of operational activi-
ties at your facility. The results of these inspections are documented in the
enclosed inspection report. At the conclusion of the inspection Mr. R. Conte,
of my staff, summarized the inspection findings for you and other members of
your staff. On balance, the findings were favorable. Of particular note was
the continued high level of performance of the operations department in the
use of their skills to minimize challenges to safety systems. However, the
results in one area are of concern and warrant our continued examination; and,
in another area, there was an apparent violation of regulatory requirements.
Of particular concern to us during this period were the circumstances that
developed during and atter a routine surveillance test of the pressurizer
power operated relief valve (PORV) during the midshift on October 25, 1985.
The issues of concern include (1) a routine test that could not be completed
because a portion of the test was not conducted correctly, (2) the unnecessary
creation of both a deficiency sheet and an exception sheet as a result of that
test and, subsequently, throwing these sheets away and (3) the confusing
documentation used to substantiate the shift supervisor's determination of
operability of the PORV. As a result of our witnessing your retest, it was
clear to us within several hours that the PORV was in fact operable throughout
the period except, of course, while it was being tested. It is also clear to
us that there was prompt involvement by your senior management in the retest.
Our early involvement in this process, however, led to your discovery of the
exception and deficiency sheets that had been thrown away. We are aware that
- 'r creantfa) information on these sheets aisc was available on other records
t..a j u r... :c a ... ..
Although we have no immediate safety concern at this point, we are concerned
with the actions that took place. Accordingly, we request that you provide us
with a report containing your analysis of this event. In particular, your
response should identify (1) any discrepancies in our understanding of th;
event as described in the inspection report, (2) the problems, their root
causes and lessons learned, and (3) corrective actions completed and/or
planned. This matter will remain unresolved pending our review of your
report.
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Also during the period, our inspectors identified one instance of your failing
to meet regulatory requirements as described in the enclosed Notice of
Violation (Appendix A). The apparent violation resulted from workers posting
uncontrolled circuit drawings and procedural notes on the inside of instrument
cabinets in the control room. In addition to following the instructions on
the attached Notice of Violation, please describe those measures in place or
planned to assure that similar problems do not exist in other instrument
cabinets outside the control room area.
Your cooperation with us in this matter is appreciated.
Sincerely,
dW lW
Willian I. Kane, Director
TMI-1 Restart Staff
Division of Reactor Projects
Enclosures:
1. Appendix A, Notice of Violation
2. NRC Region I Inspection Report Number 50-289/8.t-25
cc w/encls:
R. J. Toole, Operations and Maintenance Director, TM.-1
C. W. Smyth, TMI-1 Licensing Manager
R. J. McGoey, Manager, PWR Licensing
G. F. Trowbridge, Esquire
THI-1 Hearing Service List
Public Document Room (PDR)
Local Public Document Room (LPDR)
Nuclear Safety Information Center (NSIC)
NRC Resident Inspector (2 copies)
Commonwealth of Pennsylvania
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GPU Nuclocr Ccrp::rction 3
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bec w/encls:
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Region I Docket Room (concurrence ccpy)
Management Assistant, RI (w/o encl)
H. Thompson, NRR
W. Travers, NRR
J. Taylor, IE
J. Partlow, IE
T. Murley, RI
J. Allan, RI
K. Abraham, RI
R. Starostocki, RI
T. Martin, RI
S. Ebneter, RI
H. Kister, RI
L. Bettenhausen, RI
N. Blumberg, RI
P. Wen, RI
R. Conte, RI
D. Haverkamp, RI
W. Baunack, RI
R. Urban, RI
F. Young, RI
R. Walker, RII
H. Dance, RII
D. Falconer, RII
E. Johnson, RIV
D. Hunnicutt, RIV
J. Cummins, RIV
.
.
'
, APPENDIX A
NOTICE OF VIOLATION
GPU Nuclear Corporation Docket No. 50-289
Three Mile Island Unit No. 1 License No. DPR-50
As a result of the inspection conducted on October 18 through 25, 1985, and in
accordance with the NRC Enforcement Policy (10 CFR 2. Appendix C), published
in the Federal Register on March 8, 1984 (49 FR 8583), the following violation
was identified:
Criterion VI of 10 CFR 50, Appendix B, requires in part that documents be
properly controlled to assure.that those located at work locations have
been reviewed for adequacy and properly approved. The GPU Nuclear
Operational Quality Assurance Plan, Revision 0, September 1, 1982,
Section 3.0, " Control of Documents and Records," requires, in part, that
measures be established to control issuance and distribution of
procedures and drawings and that drawings and procedures be reviewed for
adequacy and approved prior to release. Station administrative procedure
(AP) 1001H, Revision 1, dated March 9, 1983, " Drawing Utilization,"
paragraph 4.2.6 states, in part, "...The use of miscellaneous drawings,
sketches, or notes will not be authorized on any panels, walls,
equipment, etc...."
Contrary to the above, on October 25, 1985, miscellaneous circuit
drawings, sketches and notes were posted on the inside of all eight
radiation monitoring panel access doors, located on panel right front in
the control room, and on the inside of the access door to nuclear
instrument reactor protection system subassembly C, cabinet 1 door, also
located in the control room. These drawings and notes were not properly
reviewed for adequacy or approved prior to their release.
This is a Severity Level V violation (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, GPU Nuclear Corporation is hereby
required to submit to this office within 20 days of the date of the letter
transmitting this Notice, a written statement or explanation in reply, includ-
ing for each violation: (1) the corrective steps which have been taken and
the results achieved (2) the corrective steps which will be taken to avoid
,
further violations; and (3) the date when full compliance will be achieved.
!
Where good cause is shown, consideration will be given to extending the
response time.
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-289/85-25
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 18-25, 1985
Inspectors: W. Baunack, Project Engineer, Region I
N. Blumberg, Lead Reactor Engineer, Region I
J. Cummins, Senior Resident Inspector (Wolf Creek),
Region IV
D. Falconer Jr., Lead Reactor Engineer, Region II
D. Haverkamp, Technical Assistant for TMI-1 Restart,
Region I
R. Urban, Reactor Engineer, Region I
P. Wen, Reactor Engineer, Region I
F. Young, Resident Inspector (TMI-1), Region I
Contractor Personnel: W. Apley, Associate Manager, Energy Systems,
Battelle Pacific Northwest Laboratories (PNL)
B. Gore, Senior Research Scientist, Battelle PNL
Approved By: * 6----f > H la's bf
en R. Conte, TMI-1 Restart M) nager Date
THI-1 Restart Staff
Division of Reactor Projects
Inspection Summary:
Routine and special (NRC shift coverage) safety inspection (352-hours) of
power operations focusing^*on operator and management performance; startup
- - -
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operations which included followup on rod exercise surveillance, calibration
indicators, repair of leaks in reactor building, drawing control, and storage
of combustible gases in safety-related areas; pressurizer power operated
relief valve surveillance Nuclear Safety and Compliance Committee staff
activities; and administrative controls implementation in the areas of removal
of equipment from service, instrument out of service control, caution tagging
and post reactor trip review.
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. Inspection Results:
Operations department personnel continued to conduct activities in a pro-
fossional manner and to use their skills to minimize challenges to safety
related systems. Although some inexperience was apparent, non-licensed
personnel also conducted themselves in a professional manner and properly
implemented facility procedures in conjunction with licensed personnel. The
inspectors noted a trend in which there was an apparent lapse of attention to
detail in the documentation of certain events or abnormal conditions in
various control room operations logs. In those cases other records reflected
those observations for licensee corrective action which was completed or was
initiated.
The testing program, to date, was effective in uncovering facility problems
such as the unexpected interaction between the turbine bypass valves and the
steam generator safety valves. Licensee representatives properly implemented
the startup test procedures and they found that the data, with some
exceptions, conformed to the test acceptance criteria.
Although inspectors later found the pressurizer power operated relief valve
(PORV) had in fact been operable except during testing, the licensee's
instrument and control (I&C) department poorly handled both the test and the
retention of the test and deficiency documents for the PORV setpoint
surveillance. Operations and I&C personnel inexperienced in performing the
test contributed to the problem when shift personnel initially conducted the
surveillance during the midshift.
Nuclear Safety and Compliance Committee (NSCC) staff activities meet or exceed
regulatory requirements. However, NRC staff needs to complete its review of
the NSCC activities performed by the committee.
Licensee management continued their detailed attentiveness and involvement and
generally was responsive to NRC staff concerns. Management was particularly
responsive to the PORV surveillance exception and deficiency sheets being
thrown away and to inspector observations on personnel potentially violating a
contamination boundary.
Administrative control procedures were technically adequate and, in general,
were properly implemented. Also, the licensee needs to continue their
assessment and corrective action related to the use of calibration stickers.
The inspectors identified an apparent violation of drawing control regulatory
requirements for placards, sketches and drawings inside instrument cabinets in
the control room (paragraph 3.2.5). -
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DETAILS
1. Introduction and Overview
1.1 General
At the beginning of this inspection period on October 18, 1985, the
TMI-1 Restart Staff was providing around-the-clock coverage to
assess restart operating activities. At 6:00 p.m., on October 24,
1985, this inspection coverage was reduced to 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> a day
consistent with the reduced level of testing activity and
steady-state facility operation at the 48% power plateau. This
nearly continuous observation of plant activities was maintained by
inspectors from Regions II and IV and by reactor operator examiners
from Battelle Pacific Northwest Laboratories, an NRC contractor.
Also, Region I inspectors continued 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 18-25, 1985, the significant TMI-1
restart operational milestones included: (1) completing main
turbine generator testing and electric power generation at the 40%
testing plateau, (2) completion of loss of main feedwater
reactor / turbine trip, and (3) initial main turbine generator
operation at the 48% plateau. The chronological summary of plant
operations during the period is presented below.
Date Time Operational Highlight or Milestone
10/18/85 7:00 a.m. Reactor at 7% of rated power pending
completion of turbine control valve
drain line repairs
9:05 a.m. Completed repairs to turbine control
valve drain line and placed turbine
generator on line
10/19/85 6:35 a.m. Increased power to 41%
10/21/85 6:04 p.m. Conducted loss of feedwater reactor
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trip / turbine trip
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circulation
10/23/85 2:30 p.m. Region I Administrator authorized the
licensee to take the reactor critical
and proceed with the test program at
the 48% plateau
4:12 p.m. Commenced reactor startup
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5:57 p.m. Reactor critical
8:26 p.m. Turbine generator on line
10/24/85 1:28 p.m. increased power to 48%
10/25/85 7:00 a.m. At the end of this inspection period
the reactor was at 48% of rated power,
reactor coolant average temperature was
578 degrees F arfd pressure was 2150
psig
1.3 Operational Events
As described in Inspection Report 50-289/85-24, recurring problems.
with weld failurar in two drain lines from the turbine control valve
headers had delayed the restart testing program for several days.
Repairs to tho frain lines were completed on October 18, 1985,
permitting continuation of the test program at the 40% power
plateau.
Two events occurred dut'ing this inspection period that were
considered either operationally significant or were matters of
special interest to the THI-1 Restart Staff. These events are
~ '
summarized below.
Date Operational Event
10/21/85 During post trip inspection.of t reactor
building, leaks were identified on an
emergency feedwater flange and on a steam
generator level instrument root valve (see
paragraphs 3.2.4 and,4.2.2.4)
10/22/85 Group 1 safety rods would not respond to
"in" command during pre-critical testing
The problem regarding movement of Group 1 safety rods was traced to
the inability to transfer the rods from the de hold bus to the
auxiliary power supply. The de hold bus does not provide motive
power for rod movement. The licensee suspected a malfunction with
transfer relays but the symptom was not repeated.
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1.4 Summary
Inis inspection includeo continued progress of restart testing
activities up to the 48% power plateau. 'During this period there
was one interruption of the restart testing program while repairs
were made to two leaks identified during post-trip inspection of the
reactor building. The THI-1 Restart Staff remained sensitive to an
adverse impact on shift supervisor safety duties due to NRC shift
inspector questioning and discussions of matters of a progransnatic
nature. Accordingly, the shift inspectors referred only
implementation matters or status questions to the shift s.upervisor
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. and referred programmatic matters (event followup, 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 Reviaw and Observations
During the period of October 18-25, 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
4 operating and startup activities to determine that:
--
operators are attentive and responsive to plant parameters
and conditions
--
plant evolutions and testing are planned and properly
authorized;
--
procedures are used and followed as required by plant
policy;
--
equipment status changes are appropriately documented and
communicated to appropriate shift personnel;
--
the operating conditions of plant equipment are
effectively monitored and appropriate corrective action is
initiated when required;
--
backup instrumentation, measurements, and readings are
used as appropriate when normal instrumentation is found
to be defective or out of tolerance;
--
logkeeping is timely, accurate, and adequately reflects
plant activities and status;
.
--
operators follow good operating practices in conducting
plant operations; and '
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training.
The shift inspectors' observations included, but were not limited
to, those reactor plant operation and testing activities, periodic
surveillance activities, and preventive and corrective maintenance
activities listed below.
_ __ - _ _ _ _ , _ _ . _ . _ _ _ _ _ _ _ _ . . - . _ - _
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5 l
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Reactor Plant Operation and Testina Activities
s
-- routine control' room operations including annunciator
alarm response and control room logkeening
-- operating and emergency procedures discussions with shift
supervisors, shift foremen, control room operators and
shift technical advisors
--
periodic inspection observation tours of areas outside the
control room, including diesel generator rooms, emergency
feedwater rooms, control building, turbine building,
auxiliary building, intermediate building, electrical
switchgear rooms, and outside buildings and yard areas.
-- secondary plant auxiliary operator observation rounds and
discussion of water treat system instruments, controls and
5
interlocks
--
shift preparations and conduct of turbine startup
operations following drain line repairs
--
power level increase to 25% of rated power ,
--
power level increase to 40% of rated power 's
--
startup of B condensate booster pump
--
local startup of B heater drain pump
advance management planning for, reactor trip test
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--
--
changeover from B to A heater drain pump
-- inspector operability verification of emergency diesel
generators systems valve and breaker positions
-- walkdown of secondary systems in company with an auxiliary
operator
-- instrument air compressor after cooler water trap blowdown'
-- shift turnover activities conducted by licensed operators ,
and operating crtw planning briefings conducted by shift
fere. ."
-- extensive operating crew and technical staff briefings in
preparation for reactor trip test
-- performance of loss of feedwater reactor / turbine trip at
40% of rated power
-- fire drill at the emergency safeguards motor control
center lA
L
%
_ . - . _ . ___ _ _ . - - _ _ _
6
--
temporary change notice logbook, control room tagout and
control room operator checklist implementation
'
--
turbine shell/ chest heating activities prior to turbine
generator operation
--
special temporary procedures administrative controls
implementation
--
water addition to sodium hydroxide tank to increase tank
pressure
--
crew performance of long form pre-critical checklist per
procedure 1102-2
--
crew response to unexpected apparent reduction in shutdown
margin
--
estimated critical position calculations for criticality
--
operating crew performance during reactor startup
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--
operator actions during startup in response to group IV
safety rods out interlock stopping group V control rod
withdrawal
--
operator actions during startup in response to
intermittent group I safety rods out interlock problem
--
turbine generator startup and load increase to 40% of
rated power
-- turbine load increase to 48% of rated power
--
operator actions in response to continuing main feedwater
systc= cscillations due to apparent centrcl proble= with
l
main feedwater valve FW-V-17A
! -- implementation of administrative controls for equipment
operation including caution tags, out-of-service stickers,
blue and red tags and switching logs
--
startup of B main feedwater pump -
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l cylinders found stored in close proximity to eacn other by
I backup instrument air compressor in intermediate building
-- shift foreman response to untethered pressurized hydrogen
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bottle in Hayes gas analyzer room
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Periodic Surveillance and Maintenance Testing
--
secondary service closed cooling water pump SC-P-1B
testing in response to request from maintenance
--
accelerometer vibration measurements of main steam drain
lines
--
local cycling of main feedwater regulating valves
FW-V-17A&B for post-maintenance testing of controllers and
valve position indication
--
portions of Surveillance Procedure 1303-7.2, " Source Range
Channel," regarding count rate amplifier calibration and
gain testing
--
procedure review of calibration tests for nuclear services
closed cooling water line break isolation channels A and B
--
condenser vacuum pump exhaust sampling and analysis
--
reactor building fire detector testing
--
power range nuclear instrument adjustments
--
reactor coolant system heat balance measurements
--
spent fuel cooling pump functional test
--
power imbalance detector correlation test
--
reactor coolant pump seal leakoff " bucket check"
--
reactor protection system monthly surveillance testing per
procedure 1303-4.1
--
high pressure injection and low pressure injection analog
channels monthly surveillance testing per procedure
1303-4.19
- --
radiation monitors system quarterly calibration testing
per procedure 1302-3.1
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--
control rod movement tests per procedure 1303-3.1
--
pressure switch calibrations for emergency fesswater start
and reactor / turbine trip on loss of feedwater
--
emergency diesel generator monthly surveillance testing
per procedure 1107-3
--
emergency safeguards systems monthly surveillance testing
., - - ,- -
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--
pressurizer power-oriented relief valve setpoint check
surveillance per procedure 1303-11.45
Preventive and Corrective Maintenance Activities
--
main steam drain line pipe threading in machine shop
--
packing leak adjustment to stop a leak in top of Amertap
tank TC-11A
--
collar welding on equalizing line around condensate
booster pump 1C suction valve CO-V-29C to stop a pinhole
leak
--
partial review of program for instituting and controlling
corrective maintenance activities
--
moisture separator drain tank sight glass level indication
verification
--
seal installation in C heater drain pump
--
reactor building fire detector maintenance
--
reactor building purge outlet valve preventive maintenance
(bushing inspection for wear and lubrication)
--
nuclear instrumentation channel 6 imbalance meter repairs
--
hydraulic oil addition to reactor coolant pumps
--
steam generator A emergency feedwater line flanged
connection leakage repairs
--
feedwater root valve FW-V-1093 leakage repairs
-- investigation of reported empty or low hydraulic fluid
reservoirs for snubbers in pressurizer safety valve relief
lines
--
alcohol cleaning of contacts in reactor protection system
cabinet 2 for nuclear instrumentation channel 4 log
amplifier and startup rate drawers -
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sporacle nig'n peaxing
--
repairs to inoperable controller for main feedwater pump B
recirculation valve FW-V-7B
.
't
_,
9
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-1 Restart Manager. Those items requiring additional
staff review or followup are described in paragraph 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
personnel performance. These general assessments
included, as applicable, each inspector's overall views
related to operating staff performance, fire protection,
maintenance, surveillance, radiological controls,
training, emergency planning, and physical security. The
inspectors' assessments are presented below.
2.2.2 Operating Staff Performance
Shift inspectors continued to provide many positive
comments on the knowledge level and overall quality of
'
performance of facility operating, maintenance and
technical staff personnel as described in detail in
previous inspection reports 50-289/85-22 and 50-289/85-24.
Those groups of individuals, that were closely monitored
in addition to control room operators and shift
supervisors were: shift technical advisers,
instrumentation and control (I&C) technicians, and
auxiliary operators.
The performance of certain individuals was noteworthy in
that it reflected a professional attitude. An I&C
technician took the initiative to clean the sediment out
of a moisture separator sight glass drain plug during his
troubleshooting efforts on a level control valve. A
training instructor took the initiative on a Saturday to
observe a heater drain pump seal installation. He
explained that he taught that mechanical maintenance
evolution and he wanted additional feedback on how to
improve the lesson plan. Also, as a side note, one shift
openly expressed disappointment that the post trip reactor
etartup was rescheduled for a different shift. Although
- ? : r- c:1 :::1
. . .-
'
- s
- . *e : -' i
-% '
" - ' -
a relatively large organization, tne generai comments of
the shift inspectors reflect that there is a general sense
of dedication, motivation and caring displayed by the
majority of the personnel observed.
In general, procedures continued to be properly
implemented. Specific procedure implementation problems
were noted in paragraphs 3.2.3 and 3.2.5. Further, an
inspector observed an operator using a suberitical
. , , . _ - _ _ _ __ _ _.
_
_ , - - , .
__ _ _ _. _- __ _ _ _ . _ _ _ _
- 10
multiplication "l/M" plot that was not a replica (in
format) of the procedural required plot. This had no
adverse effect on the proper method of performing the 1/M
plot since the content of the form used was essentially
the same as prescribed by procedures. The inspector
brought this to the attention of licensee management and
stated that the proper form should be used. Licensee
management acknowledged the inspector's comments.
i
Overall, operators and technicians continued to perform in
a professional manner.
2.2.3 Training
i The reactor trip and subsequent startup during this period
provided operators with excellent opportunities to gain
operational experience, especially when the integrated
control system (ICS) needed to be operated in manual.
Shift supervisors and licensee management continued their
emphasis on every event being a learning experience.
.
The licensee also conducted a fire drill during this
period and it sufficiently demonstrated the fire fighting
preparedness of the fire brigade. Based on observations
of the shift fire drill and several on-shift training
briefs, the inspectors determined that training was being
conducted in a serious manner with appropriate
participation.
i Training appeared to provide plant personnel with
sufficient skills and knowledge necessary to perform
activities in a safe and proficient manner. Steady-state
operations, as well as transient evolutions, were
routinely utilized to provide an on-the-job training
medium to increase training intensity and to accelerate
shift operational experience. Observed on-the-job
training was effectively conducted with experienced
. supervisors not just monitoring crew performance, but
providing instruction before, during, and after
evolutions. There was considerable sharing of information
r between operators, with no indication that there was an
unwillingness on anyone's part to admit ignorance on a
-
particular issue.
- ..::.-
.
-.g , :r-<j._ ,.
+ue : n. : - . - - . .
.
were minimally adequate. Operators nad little time to
spend giving checkouts, and there seemed to be little
'
uniformity as to the level of detail that went into a
checkout. However, based on observations of personnel to
date, it appears that the overall training pipeline is
4
performance-oriented.
i
I
. _ _ _
~__ _ _ . _ _ _ , _ , ,_ .__ . _ _ _ _ , _ _ _ , _ _ _ . _ _ _ . _ _ _ _ . -
11
2.2.4 Fire Protection
Fire protection measures continued to be implemented
adequately, based on shift inspector visual inspection,
review of fire brigade assignments and training,
monitoring of system surveillances conducted during the
week, and fire extinguisher checks, none of which were
past their inspection due date. At the beginning of the
inspection period, the inspectors observed two instances
where fire doors were left open or ajar primarily because
of ventilation differential pressure imbalance and
indirectly because certain personnel were not attentive to
assure that the door was closed. The inspectors trended
this observation throughout the inspection period and
noted no additional instances of fire doors being left
open or ajar.
2.2.5 Maintenance
Corrective maintenance was aggressively pursued and
promptly effected. Maintenance personnel appeared to be
well qualified and trained. However, a lack of
experienced I&C supervision on the backshift became
apparent when inexperienced technicians had problems
calibrating the PORV reset setpoint during a backshift
surveillance (see paragraph 5).
"Furmanite" repairs to the emergency feedwater header and
to a valve inside the reactor building prior to restart
'
following a planned trip demonstrated the licensee's high
priority for maintaining the plant (see paragraph 3.2.4).
2.2.6 Surveillance
I
Surveillances required by the technical specifications
were conducted at the specified frequency without
exception. Technical specification required surveillances
were provided for and controlled by a strong
administrative program which ensured they were conducted
at the specified frequency.
The calibration frequency of some instruments which were
not related to technical specifications but provided
parameter status of systems important-to-safety were not
er r*-ir.te~tly maintP.ir.Oi 25 FV! 30*?Pd bV 'hO I' P0nthi
since the last calibration of the cecay heat closed
L
cooling surge tank level instruments. This frequency is
at the discretion of the licensee.
An isolated problem was identified in the surveillance
program concerning a technical specification required
demonstration of control rod operability prior to
criticality (see paragraph 3.2.2).
l
l
.. __ _ _ _ _ _ . . - _ _. _ _ _ __ - - _ _ . _ _ _ _ .
12
Operations supervision of surveillances was excellent,
both from the standpoint of knowing what was being done
and how it affected the plant. There were a number of
times when the assigned control room operator was
significantly pressed, and in each case he stopped
distracting evolutions to concentrate on monitoring
surveillances. An especially good job was done in
preplanning of plant conditions to allow for the effective
accomplishment of surveillances.
All surveillance procedures reviewed were adequate. One
potential problem concerned uncontrolled labelling and
schematic diagrams found in the back of the radiation
monitor panels. It was not determined if they were ever
used during surveillance testing (see paragraph 3.2.5).
2.2.7 Radiological Controls
Contaminated areas were posted and maps showing radiation
and contamination levels were present at entry pads.
Several components with potential leakage problems were
encased within transparent yellow plastic to contain
leakage. Tygon drain tubing crossing passage areas and
drain openings was taped in place. Cleanliness and
attention to minimize the spread of contamination were
apparent.
For radiation work permit (RWP) entries, radiological
control (radcon) technicians had considered ALARA
requirements. Low dose rates were expected in the regions
visited. Proper dosimetry including neutron monitoring
and/or continuous technician coverage were provided in
accordance with RWP requirements. Discussions with a
radcon foreman on the intent and interpretation of the
" continuous monitoring" requirements indicated a proper
concern and emphasis upon area surveys and job planning to
minimize personnel dose.
2.2.8 Physical Security
On one occasion the shift inspector discovered the
card-entry door to the control room complex ajar. A
security guard arrived within about two minutes to
investigate and secure the door. Based on routine
5, ,
. .e ;' : c..'*- .e: r c:- r :: A : !: -
r;;rd
performance no adverse conditions or problems were
identified in this area.
2.3 Conclusion
Personnel performed in a professional manner. There were procedure
implementation problems, but on a closer review it appeared they
were due to individual inexperience or lack of familiarization and
none adversely affected safe operation of the facility. Actual
. - - . - - - - _ _ . . . - - . . -
,
13
plant experience continued to be a valuable training vehicle to
support safe power operation. The operations department performed
well during major challenges to their skills, e.g. the 40% reactor
trip test and the subsequent natural circulation test during which
natural circulation was lost.
Overall, maintenance and surveillance activities were properly
,
conducted, although some examples of poor implementation practices
were noted. Area radiological contamination control continues to be
noteworthy. Radiological control procedures were properly
implemented with health physics personnel demonstrating a genuine
concern for worker radiation protection.
3. Plant Operations
3.1 Routine Review
The TMI-1 Restart Staff inspectors periodically inspected the
facility to determine the extent of the licensee's compliance with
general operating requirements of Section 6 of the Technical
Specifications (TS) in the areas listed below.
--
review of selected plant parameters for abnormal trends
--
plant status from a maintenance / modification viewpoint
including plant housekeeping and fire protection measures
--
control of ongoing and special evolutions, including
control room personnel awareness of these evolutions
. --
control of documents including log-keeping practices
--
implementation of radiological controls
'
--
implementation of the security plan including access
control, boundary integrity and badging practices
The inspectors focused their attention on the areas listed below.
--
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
--
followup items identified by snift inspector activit:es
(paragraph 2)
--
areas outside the control room
--
selected licensee planning meetings
1
- _ . - - - . - . _ . ,,-, . , , . . . - . , . - - . - , . . - . , . , . . . - - _ . . . , - . , , - . , _ - _ - - - . . _ _ - - - - - _ _ ~ . . . , - . .. -
14
As a result of this review, the inspectors reviewed specific
concerns or events in more detail as described in the sections that
follow.
3.2 Findings
3.2.1 General
Licensee management continued their detailed involvement
in all phases of plant operation. The operations manager
directed major day-to-day plant activities while shift
supervisors were held responsible for accomplishment of
directives. Major plant evolutions were directly
supervised by senior plant management with additional
licensed personnel present to monitor plant parameters.
After achieving the 48% power plateau, shift supervisors
were allowed to fully direct routine shift activities and,
thereby, demonstrate their management capabilities.
'
Licensed shift supervision maintained a high level of
responsiveness to the concerns identified by the
inspectors. These concerns included snubber fluid levels,
water in the instrument air aftercooler water trap and
leakage of a condensate tank recirculation line valve.
The licensee's efforts in resolving and providing
corrective actions concerning the PORV documentation and
operability problems (see paragraph 5) further exemplified
their regulatory responsiveness. As an additional
example, licensee management was responsive to NRC
concerns on how major test briefings were conducted. They
conducted the briefing for the 40% trip test in the south
auditorium which was more environmentally suitable. The
briefing also included a discussion of response actions
for operational problems that might be encountered.
The high motivation of licensee management apparently has
filtered down to certain employees as described in
paragraph 2.2.2 on the motivation of personnel observed
performing work activities.
The radiological controls department was responsive in
resolving an inspector's observation of an apparent
violation of a contamination control barrier-(NRC
Inspection Report 50-289/85-24). Radeon department
-. --
- :n . :r- - :b v:e re-er. et in : 1.~> ca ru~
12censee representativos cetermined tnat tne worters were
moving paint into the contaminated area. The inspector
had no further comments on this matter.
In general, administrative procedures were properly
implemented as described in paragraph 7. However, with
respect to log keeping, details of certain events were not
provided in the control room operator's log or shift
i
- -----*----y--e--- - + - - - - - - - - -r w
_ - , - , _ _ . - - , .-y --
-r - - * - - % , .o,y9,---
-
9
, . . - . . -- -- -- -
15
,
foreman's log. The leaks found in the reactor building
- (see paragraphs 3.2.4 and 4.2.2.4) were not logged but
i were recorded in another plant record, a work request, to
initiate repair action.
1 The safety rod out limit interlock prevents movement of
- reactor control rod groups 5 to 7. The operational
actions taken to correct the problem were not recorded.
When this was brought to the plant operations manager's
attention, he had a " late entry" placed in the shift
foreman's log. Considering other log entries during this
period and previous inspection periods, the inspector
i stated that the above log entry discrepancies were not
characteristic of the past performance by the' operator.
'
The inspector also stat 4d that this area will be trended
during subsequent routine NRC reviews. The safety rods
i
out interlock problem is unresolved pending further review
(289/85-25-01).
.
3.2.2 Rod Exercise Surveillance
A shift inspector witnessed portions of surveillance
procedure 1303-3.1, " Control Rod Drive Movement"
(see paragraph 2.2.6). The procedure successfully
,
demonstrated the operability of all safety rods as
required by Technical Specification (TS) 4.7.1, but the '
'
shift inspector questioned how the surveillance would be
current for startup when TS 4.7.1 requires the rod
exercising only during power operations. P
1
The resident inspector reviewed the surveillance data
records and confirmed the shift inspector's findings. The
TS 4.7.1 surveillance is performed to ensure that a stuck
rod does not exist prior to returning to power operation
or that a stuck rod does not go undetected for long
periods of time while at power. There were no
,
provisions in the licensee's startup procedure to perform
! this surveillance during or after an extended period at
. hot shutdown. The licensee was aware of the problem and
l was manually tracking this type of surveillance to assure
its completion prior to startup. The inspector discussed
the possibility that this should be part of the reactor
l startup checklist. Licensee representatives' acknowledged
this and stated it would be considered. The inspector
- it em W. a.c.r.p'. r *
i
- .a ! n .. .: o -
- . ' .4 ... :
4.7.1 and nad no further comments.
3.2.3 Calibration Stickers
During tours in the turbine and intermediate buildings,
shift inspectors noted various instrument sages with
,
calibration stickers that indicated the gages were past
due for calibration. When challenged, the licensee
i
i
! '
L
-- - ---- - - - - . - _ _ . . .. . . . . - - , - - . - - . . . - - . - - - - - - - , - - - - - . . , - - . . .
-
- ~ . . . . - . . - . . .
16
provided sufficient records, on a sampling basis, to
demonstrate the calibration of gages within the specified
intervals.
,
The resident inspector queried licensee representatives as
to why the calibration stickers were not updated.
Licensee representatives indicated that the calibration
stickers were to be phased out and replaced with
individual gage records that are now being used to assure
proper calibration. The problem is that many calibration
procedures still require the use of stickers and it is a
low priority administrative effort to change these
procedures. Based or. this review and review of data
related to testing in past inspection reports, the
inspector concluded that operators used calibrated gages
for regulatory required functional testing and control
room parameter monitoring. However, the inspector stated
that calibration stickers indicating past due calibration
were confusing from an op.:stor's viewpoint in that the
reliability of the instrument could be questioned when
data was needed for operations or testing. Licensee
management acknowledged the problem and stated that the
calibration sticker problem would be resolved on a higher
priority basis. The inspector had no further comments in
j this area.
3.2.4 NRC Review of "Furmanite" Process
!
The restart staff reviewed the licensee's repairs to the
leaking components found during the reactor building
inspection (see paragraph 4.2.2.4). A sealant compound
"Furmanite" was injected into the leaking area and formed
,
a new gasket thus stopping the leaks. In the case of the
flange leak, a machined sealing ring was bolted over the
outer surfaces of the two flanges to form a void that was
filled with Furmanite. ants void formed a new pressure
boundary and the injected Furmanite then sealed the
boundary. In the case of the leaking valve the Furmanite
was injected between the body and the bonnet and formed a
new gasket.
,
The licensee's plant engineering group prepared a safety
evaluation (10 CFR 50.59 review). No. 85-250-M, to
determine the acceptability of Furmanite for this
- *
i -
,
- , :At * *ryf ,
. *' * *
,a*g ,e rs
"...No new unreviewed safety questions.... The flange
injection clamp adds [approximately) 15 lbs. to the
existing flange assembly...[which was] determined to be
, insignificant from a dead weight concern...[the added]
mass does not degrade any previous seismic
classification...."
While the work was in progress, the inspectors queried the
licensee as to whether or not stresses on the flange bolts
had been considered in the safety evaluation and the
- .- - - - ---- - - - - . . - - . - _ - - , . - - - - - - - - - - - . . .--
1
. 17
inspector determined that it was not. The vendor's
engineering group was contacted to perform such a
calculation. Furmanite provided an analysis which ;
indicated the bolts would not be overstressed. This was !
based on normal operating pressure of 900 psig leaking and
being sealed by the Furmanite. The inspectors determined
that, by applying higher pressures than the 900 psig, the
bolts would not be overstressed.
The inspectors and licensee representatives discussed the
effects of Furmanite injection during a telephone
conversation with tne vendor engineering representative.
The vendor representative noted that although Furmanite
was injected under pressure, this pressure tended to
relieve itself. The vendor representative stated that tha
last segment of Furmanite installed might place some
stress on the flange bolts but it should not be signifi-
cant. The vendor representative also stated that, from
their experience, stress analyses were not required for
similar design rated flanges.
The inspectors reviewed the licensee safety evaluation.
Based on this review, discussions with the licensee,
discussions with Furmanite, and review of the Furmanite
safety analysis for bolt stresses, the inspectors
determined that the licensee's initial safety evaluation
was acceptable. While the evaluation could have been more
thorough and included an analysis of flange stresses,
their not being included did not constitute a serious
review deficiency. The inspector noted that safety
evaluation (85-250-M) also included a review of the
specific procedure for applying Furmanite to this flange. -
The licensee's generic procedure 1410-Y-44, "Use of
Furmanite," was used in this process.
The staff concluded that the flange bolts would not be
overstressed and the Furmanite process is an acceptable
temporary repair method. The licensee committed to repair
the joints prior to returning to power after the
completion of the Spring 1986 eddy current outage. This
matter is unresolved pending completion of licensee action
as committed to above and subsequent NRC Region I review
(289/85-25-02). -
3.2.5 D-r !~~ ce-* ci
During witnessing of a surveillance in a radiation
monitoring system (RMS) cabinet located in control room
console panel right front, the shift inspector observed
circuit drawings and typed procedural notes posted on the
inner cabinet door (see paragraph 2.2.6). Further
inspection revealed that uncontrolled and unapproved
.
'
drawings and procedural notes were posted to the inside of
all eight RMS panel access doors and reactor protection
system subassembly cabinet "C."
- . _ _ - __ _ . _ _ . _ . _ _ _ _ _ - _ _ _ - _ ____
18
Administrative procedure (AP) 1001H, " Drawing Utiliza-
tion," states that the use of drawings and notes are not
authorized on plant panels. All drawings and procedures
observed on the cabinet doors were removed by the
instrument and controls supervisor.
The posting of uncontrolled and unapproved drawings and
procedures on cabinet doors is contrary to 10 CFR 50,
Appendix B, Criterion VI and licensee procedure AP 100lH
and constitutes an apparent violation (289/85-25-03).
3.2.6 H2/02Storage
A shift inspector tour of the intermediate building
revealed that hydrogen and oxygen gas cylinder bottles
were stored side by side. The gases were used as calibra-
tion gases for the reactor building hydrogen monitors.
The TMI-l Restart Staff determined that, although the
bottles were in seismically designed storage racks, this
situation was not strictly in accordance with the
licensee's occupational safety and health manual. Later
review by licensee representatives in consultation with
the Harrisburg OSHA (Occupational Safety and Health
Administration) office determined that the storage aspects
were acceptable. Plant engineering personnel also re-
viewed the situation and they concluded that no fire
hazard existed. The adequacy of the licensee's hazard
analysis for this area is unresolved pending a subsequent
inspection (289/85-25-04).
3.3 Conclusion
Licensee management continued their detailed attentiveness and
involvement in daily activities. In general, highly motivated
managers appear to be instilling that same motivation in plant
personnel,
i
There may be a need for more detailed recording of events or
- abnormal conditions in the control room logs when plant personnel
! make observations or conduct activities. A licensee decision is
- needed on whether or not to use and/or rely on calibration stickers
l on instruments in the plant. Apparently, this decision was being
held up because numerous facility procedures are affected by that
'
decision.
l
The licensee's post-trip review met the intent of the Salem AWS
(anticipated transient without scram) corrective actions. However,
! there could have been more plant engineering review and involvement
on the stress analysis for the flange bolts during the planning
l phase for the "Furmanite Repairs." The licensee's 10 CFR 50.59
l evaluation nevertheless was adequate to meet the requirements of
l that rule.
i
L
. 19
The drawing control problem was an apparent violation of regulatory
requirements. However, it was not characteristic of the licensee's
overall program since drawings and procedures available for use
inside and outside the control room were verified to be controlled
copies when checked during previous inspections since the program
problem was identified in this area in 1981.
4. Startup and Power Escalation Testing
4.1 Scone of Review
4.1.1 Test Witnessing
At various times during the inspection period, the inspec-
tors witnessed testing in progress on a sampling basis.
However, test procedure (TP) 800/2, " Trip on Loss of
Feedwater," and TP 800/8, "RCS Overcooling Test," were
witnessed in their entirety by the THI-1 Restart Staff.
The tests were observed to verify that:
--
tests were conducted in accordance with
appropriate test procedures;
--
prior to performing tests, an adequate briefing
was conducted for operations personnels
--
test prerequisites and initial conditions were
met;
--
applicable technical specifications were
complied with;
--
operator actions were correct;
--
test engineers were knowledgeable in their
,. duties; and.
--
test results were acceptable.
In addition to TP 800/2 and TP 800/8 witnessing, the
following tests were observed and/or their test results
independently reviewed by the TMI-1 Restart Staff during
this inspection period. -
-- Tr c?C/*, "" 't 'es! ' Str:^ r:r-
-
ce*"
--
TP 836/1, "Feedwater System Operation and
, Tuning"
-- TP 849/1, "ICS Tuning at 40% Power"
--
TP 846/1, "Incore Thermocouple Operations Test"
--
TP 885/2, " Turbine Bypass Valve Test"
_ _ _ - - -- -. __.
. 20
--
TP 800/2, " Trip on Loss of Feedwater"
.
--
TP 800/8, "RCS Overcooling Test"
--
OP 1105-14. " Loose Parts Vibration Monitoring
Data"
--
RP 1550-01, "Incore Detector Checkout"
--
RP 1550-04, " Power Imbalance Detector
Correlation"
- 4.1.2 Test Results Review
Test results from the testing program for the 40% power
plateau were reviewed by the inspector to verify that:
--
test changes were approved and implemented in
accordance with administrative procedures;
--
changes did not impact the basic objectives of
the test;
--
test deficiencies and exceptions were identified
and resolved and resolutions were acceptables
--
the cognizant engineering group has evaluated
the test results and signified that testing
demonstrated that design conditions were mets
and.
--
test results vere within established acceptance
criteria or properly resolved.
4.2 Licensee Test Results and NRC Findings
,
- Licensee performance of key tests is described in this section. The
discussion includes a summary of key test objectives and test
results: test performance including operators, test engineers and
equipments and pertinent findings and outstanding problem areas
-
identified and/or NRC findings as a result of testing.
4.2.1 Reactor Trip on Loss of Feedwater/ Turbine Trip (TP 800/2)
.: ..
' ~
_; 'r' --
Restart condition 2.b requires that prior to operation
above 48% power, the licensee demonstrate automatic
initiation of emergency feedwater (EFW) pumps upon loss of
both main feedwater pumps. This test was performed on
October 21, 1985, in accordance with TP 800/2, " Reactor
Trip on Loss of Feedwater/ Turbine Trip," during which both
main feedwater pumps were tripped. Following the trip of
, 21
1
the feedwater pumps, the following events were expected to
occur.
--
reactor trip on anticipatory loss of feedwater
--
turbine bypass setpoint transfers to 1010 psig
--
turbine trip coincident with loss of main
feedwater pumps
--
containment isolation on reactor trip
--
OTSG levels control at 30 inches using EFW flow
--
all three EFW pumps start automatically.
Operations and test personnel were stationed in the
control room, at the remote shutdown panel, at the two
motor driven and one steam driven EFW pumps, and outside
the plant to visually monitor which main steam relief
valves actually opened. Recorder charts were connected at
the EFW pumps and remote shutdown panel for data
recording.
Personnel were stationed at all three EFW pumps to assure
proper operation of the pumps. To temporarily rectify a
previous problem in which the steam supply relief valves
to EFP-1 lifted during pump startup, one steam supply
valve from the "A" OTSG (MS-V-13A) was shut and disabled
from automatic actuation to reduce steam flow and preclude
actuation of the relief valves. The previous actuation of
these relief valves was detailed in inspection report
50-289/85-22.
The operator stationed at EF-P-1 was also tasked with
opening of MS-V-13A manually, 11 necessary. MS-V-13B was
allowed to operate automatically to supply steam to
EF-P-1. In accordance with TP 800/2, after automatic
actuation of EF-P-1 was demonstrated, EF-P-1 was secured
from further operation so that motor driven pumps EF-P-2
A&B could control OTSG 1evel.
4.2.1.2 Observations and Findinas -
Tr -!- ~~ e n r cf r?r-t c~ e r s. r ~ .- * : ~ * t r o. --*-r? w--
observec in the control room ano in the interracciate
building at the emergency feedwater pumps. The following
observations of operators and plant equipment were noted.
Control Room
Overall, operator performance appeared to be good.
Operators were attentive, maintained their stations,
monitored appropriate instrumentation, and reported
.
.
23
important readings and alarms. Plant operations for
this test were directed by the plant operations
manager. Test direction was formal, and operators
were kept informed of overall plant status, test
concerns, and impending actions. Procedures were
followed completely.
Since a reactor trip took place, the immediate
actions of ATP 1210-1, " Reactor Trip / Turbine Trip,"
were followed. A shift foreman read the procedure
actions aloud and received formal responses from
operators concerning completed actions.
Communications during performance of post-trip
actions were good. In general, annunciators were
properly acknowledged.
Proper communications between the control room and
plant stations, such as the EFW pumps and the outside
safety valve watch, were maintained. The test was
conducted according to procedures test prerequisites
were satisfied and test limitations were observed.
Intermediate Buildina
The motor driven EFW pumps (EF-P-2 A&B) and the
turbine driven EFW pump (EF-P-1) were manned by
operations personnel who wc e in direct communica-
tions with the control room. Test engineering
persennel were present to take data for the test, and
plant engineering personnel were present to monitor
inservice test parameters.
All three EFW pumps started on loss of main feedwater
within the required time frame. As noted previously,
one steam supply valve was shut to EF-P-1. This did
not affect proper operation of EF-P-1, and the steam
supply safety valves did not lift. The operator
stationed at EF-P-1 was available to open the other
steam supply valve if it had been required. However,
as noted in inspection report 50-289/85-22, a
satisfactory permanent resolution to the lifting of
EF-P-1 safety valves on normal pump starts is
required. As required by the test procedure, EF-P-1
was secured after approximately 12 minutes of
y . . ,
1 . . : . c. 3 ;; . . . 3 7,. . .. t . e .,
maintain 0T56 levels ano for tne natural circulation
test, TP 800/8.
. 23
Test Results
The test results indicated that actuation times for
all three EFW pumps met the test acceptance criteria.
For comparison, the results from the previous test as
conducted per TP 700/2 as well as the results of TP
800/1 are included in the following table.
Acceptance
Actuation Time Criteria
(seconds) (seconds)
Turbine Driven Pump
(EF-P-1) 15 20 <40
Motor Driven Pump
(EF-P-2A) 3 1.8 <15
Motor Driven Pump
(EF-P-2B) 3 2.0 <15
In addition to the automatic start of the EFW pumps
after shutting off both main feedwater pumps the
reactor tripped: the turbine tripped; partial
containment isolation on reactor trip functioned and
OTSG 1evels were controlled at approximately 30
inches using EFW pumps. Another test objective, that
the turbine bypass valve function at a turbine header
pressure of 1010 1 10 psig, did not appear to be
proven by the test. Although the turbine bypass
setpoint was found to be in calibration, the turbine
bypass valves did not control turbine header steam
pressure as expected. This problem is further
detailed in paragraph 4.2.3 below.
4.2.2 RCS Overcoolina Test (TP 800/8)
4.2.2.1 Test Performance
The licensee prepared test TP 800/8, "RCS Overcooling
Test," to further demonstrate plant operation in a natural
circulation mode and to gain additional real plant data
cenectr.ing this operatien. The barie ch,4ectiva ef the
test was to demonstrate that the control rocm operators
could properly throttle EFW flow to prevent overcualing
the reactor coolant system (RCS) while feeding the OTSGs
following loss of the reactor coolant pumps (RCPs). The
OTSGs were to be fed from an initial level of 30 inches in
the startup range to a level of 50% (245 inches) in the
operating range. During this transition, it was desired
to start and maintain natural circulation.
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
24
TP 800/8 was not part of the restart test program
committed to the NRC for the startup of 'INI-1 and
satisfactory completion of all aspects of this test were
not required for satisfactory completion of the startup
test program. TP 800/8 was scheduled following the trip
during performance of TP 800/2 since the reactor would be
shut down at this time. The driving force for natural
circulation was to be an expected decay heat of 0.5 to
0.7% of rated power based on two to three days of
operation at 40% of rated power.
Since this test was to take place immediately following
the reactor trip, the operator and test engineer manning
as stated for TP 800/2 was also in place for this test.
The RCPs were stopped approximately 25 minutes after the
reactor scram and after plant conditions had stabilised.
The motor driven EFW pumps were already running and
maintaining OTSG 1evels at approximately 30 inches.
Because of transients experienced on the restart of RCPs
during performance of natural circulation test TP 700/2,
an engineering evaluation had been done for TP 800/2.
This resulted in a major revision to TP 800/2 which
included setting a limit for reactor coolant system hot
leg temperature (Th) prior to restart of the RCPs and
manually controlling steam generator pressure just prior
to and immediately after the starting of RCPs to minimize
the secondary side pressure transient. An extensive two
hour briefing was given to the operating crew which was to
perform TP 800/2 and TP 800/8. This briefing included
test performance, operator actions, possible problems, and
expected plant responses in natural circulation and return
to forced circulation. NRC inspectors attended and
verified the acceptability of this briefing.
4.2.2.2 General Observations - RCS Overcoolina Control Test
Since this test was done immediately following the reactor
trip per TP 800/2, the observations concerning operator
actions for TP 800/2 also apply to the performance of TP
800/8. As noted previously, the objective of the test was
to raise the level in both OTSGs equally from 30 inches to
245 inches using EFW flow, raise OTSG 1evels without
overcooling the RCS, and establish and maintain natural
tir d.stion.
Apparently, because there was insufficient decay heat, the
licensee was not able to raise the OTSGs to the 50% level
(operating range) and maintain natural circulation.
However, a fundamental objective of the procedure was met
in that the operators were able to throttle EFW to the
OTSGs without overcooling of the RCS. It appears that
__ _ _ _ _ . - _ _ _ _ - _._ _ __. _ -_ _ _ _ ._ __ _ _ _ .
25
approximately 20 minutes after tripping of the RCPs,
4 natural circulation was achieved for a short period of
time in that a 30 degrees F temperature difference was
obtained between Th and Tc; and Th and incore thermocouple :
temperatures were tracking. Th increased initially,
- reached a peak temperature of 556 degrees F at
i approximately 15 minutes then decreased in a continuous
manner. The behavior of Th followed closely with the .
'
analytically predicted model (GPU study TDR-410. "RETRAN
Analysis of the 'INI-140% LOFW & Transition to Natural
Circulation Startup Test") with the differences only in
absolute peak Th value and the timing of reaching the
peak.
Although Tc followed MSG pressure, because of very low
decay heat and possible excessive steaming in MSG "A",
the desired OTSG level of 50% operating range was not
i accomplished before OTSG "A" pressure dropped below 750
psig. The 750 psig OTSG pressure was one of the criteria
,
to restart the RCPs per test procedure. The RCPs were
- subsequently restarted to establish the forced circula-
'
tion.
!
!
The possibility of the depressurization in OTSG pressure
below 750 psig during, the test had been analyzed in the
- licensee's study (TDR-410). This was discussed in the
briefing prior to the test. The inspector also noted that
smooth natural circulation had been lost before forced
, circulation was established. Although, all test objec-
tives were not completely met, licensee engineers stated
l they considered the test a success because sufficient
- information was obtained. The licensee is in the process
j of evaluating the test results. Appropriate information
, derived from this test will be issued for future plant
operation Ruidelines.
I 4.2.2.3 Licensee Post-Trio Data Review
i
l'
The resident inspector attended the licensee's post trip
review of the trip test on October 21, 1985. The licensee
review was required by Administrative Procedure 1063,
" Reactor Trip Review Process." This was the first time
that the licensee performed this review since the licenses
significantly revised the procedure. As a result, it took
- .,
- . ;,,,, .
.e.
.
. . . , . -
.
,.<;.- : ...,,..s .i
respect to gathering and properly reviewins tr.e cata.
a The licensee noted several minor administrative
i inconsistencies in the procedure that will be corrected.
l The post trip review identified the problem associated ,
with turbine bypass control valves and main steam safety I
'
valves interaction which are described further in para-
i graphs 4.2.1.2 and 4.2.3 of this report. Subsequent to
t
the post trip review, licensee representatives required
- that an independent safety review be conducted addressing,
specifically, the safety valve-turbine bypass valve >
- interaction problem.
!
l
. _ - _ . , _ , . _ _ - . . _ _ . _ _ . _ _ _ _ _ _ _ _ _ _ . _
. _ _ _ _ _ . _ _ _ _ _ . _
_ _ _ _
26
The inspector independently reviewed the completed
enclosure 1. " Post Trip Review of AP 1063," and the
recorder strip charts and verified that the data required
by enciesure 1 was retrieved with no significant ,
deficiencies noted. The inspector also reviewed the i
minutes of the independent safety review noted above.
This review concluded that the manner in which the
secondary system responded was not a safety concern and
the plant could be safely returned to power. The
inspector concluded that the procedure adequately
evaluated plant performance to the extent necessary to
reach a decision related to startup. In addition, the
inspector confirmed the licensee's conclusion.
4.2.2.4 Post-Trio Reactor Buildina Inspection
Immediately following the loss of feedwater
reactor / turbine trip on October 21, 1985, a shift
inspector accompanied licensee representatives into the
reactor building for a post-trip inspection. Two leaks ,
'
were identified during the licensee's walkdown of the
reactor building. The leaks were a flange leak on an
emergency feedwater spray ring header on once through
steam generator (OTSG) 1A and a valve body-to-bonnet leak l
on a steam generator level transmitter root valve,
FW-V-1093. Both leaks were repaired by using a process
known as "Furmaniting," as described in paragraph 3.2.4.
The licensee's inspection of the reactor building was
thorough and adverse conditions were properly identified
to the operating shift.
4.2.2.5 Effect of 40% Reactor Trio on RCS and OTSG Leak Rates
Based on data review of surveillance procedure (SP)
1301-1, " Shift and Daily Checks," and SP 1303-1.1,
" Reactor Coolant System Leak Rate," the inspector noted
i
that both RCS and OTSG 1eak rates on the day following the
trip test (October 22, 1985) remained well within the l
technical specification's limits and were consistent with
'
1
the previous day's result. No abnormal conditions were
< observed. ,
,
4.2.3 Turbine Bypass Valve Testina (TP 885/2) -
n ..,a er '
7- ee-t- "..;.,.....,..,,,,...4.
.
, ' in
conjunction witn it ELL,2 "heactor 1 rip Test." The tes.
objective was to verify that the six turbine bypass valves
opened fully within three seconds after trip of the
turbine, and that the turbine bypass valve functioned at '
i
1010 psis i 10 psig. During performance of TP 800/2, the
main feedwater pumps tripped causing both a reactor trip
!
and turbine trip. During the pressure increase in the
steam headers, the turbine bypass control setpoint is
expected to move to 1010 psig and attempt to control steam
i
'
i
h
- - _ _ _ . _ _ _ _ . _ _ , _ __,_ _ _.___. _ . _ ___ _ _ _ _. _ _ _ _ _ . -
.. 27
.
pressure at this level. All the turbine bypass valves
should fully open in less than three seconds. Since the
bypass valves alone may not control the full header
pressure transient, some of the main steam safety valves
would then open to relieve further increases in header
pressure.
Although the turbine bypass valves are not safety related,
the results of this test warrant further review. During
the test, the bypass valves failed to fully open. Since
the valve indication limit switches are set at 5% and 95%
the actual amount that the bypass valves opened was not
known. However, post-test graphs indicated that
integrated control system (ICS), turbine bypass "B" loop
demand (valves MS-V-3A, 38, and 3C) received an 30% open
demand signals and "A" loop demand (valves MS-V-3D, 3E,
and 3F) received a 30% open demand signal. Hence, the
bypass valve opening times could not be measured.
The failure of the turbine bypass valves to fully open was
explained by the fact that the main steam safety relief
valves opened before the turbine bypass valves. Based on
visual observations of an operator stationed for this
purpose, it appears that all eighteen mai steam safety
relief valves lifted. The lifting of the relief valves
apparently took pressure control away from the turbine
bypass valves.
Subsequent to the test, based on review of test graphs,
calibration of steam pressure instruments, and the reac-
tion of the ICS, the licensee initially concluded that
some main steam relief valve set points may be set too
low. The inspector reviewed test data for the setpoint
test of six safety relief valves performed April 15, 1985,
which were tested in pince while the plant was at normal
operating temperature. This data indicated that relief
valves were properly set.
The licensee committed tos (1) document a test exception
for the test results, with a test to be reaccomplished
during the 100% trip test, (2) test the set points of the
main steam safety valves and evaluate the need to set them
at a higher pressure prior to going beyond the 75% power
plateau (an NRC hold point), and (3) document this
cm f et ; in a. Ie*ter :: the P.neten 7 84-tetrtr: ur.
Also, Tp 800/2 will be accomplished at 100% power, which
tests the ability of the turbine bypass valves control
setpoint to transfer and control pressure at 1010 psis
following a reactor trip. This test problem is unresolved
pending completion of licensee action as stated above'and
subsequent NRC review (289/85-25-05).
28
4.2.4 Unit Load Steady State Test (TP 800/5)
The steady state plant parameters as measured per TP 800/5
at 40% power plateau continuously showed good agreement
with the predicted values. As noted in inspection report
50-289/85-24, at the 15% power level these values showed
some deviation. Tave was expected to be 579 degrees F and
actually was found to be 568 degrees F. However, Th and
Tc measurements correlated well to expected values. Near
the 15% power level the relationship of Tave to reactor
powar level makes the transition from an increasing linear
relationship to a constant Tave relationship. Tave
measurements at 25% and 40% power levels were as
predicted.
The licensee again performed the test at 15% power during
the startup after the 40% trip test. The test results
were approximately the same as before. Discussions with
B&W indicate that a Tave of 579 degrees F could be
achieved if OTSG water levels were reduced from 30" to 25"
or 26". However, the plant operators are reluctant to
steam down to these low levels.
Test engineers are evaluating a test exception for this
data point since the Tave data at higher power levels is
as expected and the plant does not normally operate for
lengthy periods at 15% power.
4.2.5 Loose Parts Monitoring (OP 1104.14)
The licensee continued to record loose parts monitoring
base line data at each power level plateau. Sound levels
were recorded at 40% power both before and after the
reactor trip at 40%. A B&W technician was on hand to
racntd data and to parannally monitor andin channela. Nn
loose parts or significant unusual noises were detected.
4.2.6 Core Power Distribution Verification (RP 1550-08)
The detailed core power distribution at the 40% power
plateau was measured by the licensee per procedure RF
1550 08, " Core Power Distribution Verification " using the
~
incere detector system. The incore detector system
contains fifty-two incore flux detector assamblies with
'. . :. s . .. ,.
.: . .
. . . .
following results:
-- The readings from symmetrical location detectors
were within 10% of the symmetrical group average
values.
-- The measured radial peaking factor for each fuel
assembly was consistent with the analytically
predicted value. The comparison of the highest
measured radial peaking f actor (1.291) at core
29
location K-11 agreed closely with the predicted
value of 1.298.
--
The measured total peaking factor in each fuel
assembly also agreed consistently well with the
predicted value. The highest measured total
peaking factor of 1.585 agreed well with the
predicted value of 1.462 and was within the
established acceptance range of 12%.
--
The measured linear heat rates accounting for
various uncertainty factors were within TS 3.5.2.7 limits, as indicated in the following
table.
Axial Location From Measured Maximum Maximum Allowable
Bottom of Core Linear Heat Rate Linear Heat Rate
(ft) (kw/ft) (kw/ft)
11.14 2.490 15.20
9.43 4.496 16.26
7.71 4.942 17.10
6.00 4.756 17.50
4.29 4.422 16.31
2.57 4.311 14.37
0.86 3.159 11.48
All results were acceptable.
4.2.7 Power Imbalance Detector Correlation Test (RP 1550-04)
Power imbalances from power range channels (NI-5 through
8) were fed to the reactor protection system to provide
the power-flow-imbalance trip. The licensee performed an
out-of-core imbalance calibration using information from
the incore detector system per test procedure RF 1550-04,
" Power Imbalance Detector Correlation Test," Revision 9.
Through test data review, the inspector noted that an
excellent linear relationship exists between the indicated
out-of-core power distribution and the actual measured
incore values. The slopes of measured out-of-core
imbalance to incore imbalance were 1.22, 1.23, 1.12, and
1.15 for NI-5, NI-6, NI-7, and NI-8, respectively. The
acceptance criterion for this correlation slope was
grrater ths- 1.'5. Uren cert?etien of *kir tc5*. the
reactor protection system channel C c1116rtr.ca amplifier
gain from NI-7 input was adjusted by instrument and
controls technicians in accordance with procedure SP
1303-4.1 Appendix B. " Procedure for Changing Scaled
Difference Amplifier (Delta Flux) Gain," on October 21,
1985. The inspector verified that the actual " difference
amplifier" sain setting K value of 5.035 (corresponding to
an imbalance slope of 1.15 as described above) was
properly implemented in the calibration. The inspector
-__ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
30
also noted that during this test the quadrant power tilt
values which ranged from 2.01 to 2.71 were all within the
TS 3.5.2.4 limit of 3.52.
4.2.8 Restart Condition Verification
Restart condition 2.b stated the following:
" Prior to operation above 48% power, GPU
Nuclear Corporation shall demonstrate
automatic initiation of EFW pumps upon
loss of both feedwater pumps."
As discussed in paragraph 4.2.1, this was demonstrated by
performance of TP 800/2. The inspectors verified
satisfactory perforinance of TP 800/2 and that the required
restart condition was met.
4.3 Conclusion
Testing for the 40% power plateau was accomplished in accordance
with procedures, data were acceptable, and test objectives were met
or proper test exceptions taken. Licensee management was responsive
to inspector observations. Problem areas were quickly corrected and
actions were taken to preclude their recurrence. Overall, licensee
performance in the test area can be considered acceptable and, to
date, test results are acceptable to proceed with the startup
program. The adequacy of the OTSG safety valve settings needs to be
resolved.
5. Pressurizer Power Operated Relief Valve (PORV) Setpoint Check
5.1 Discussion
on October 25, 1985 the NRC shift inspector witne==ad portions of
surveillance procedure 1303-11.45, "PORV Setpoint Check," Revision
5, September 3, 1985, from the control room. Two instrument and
control (I&C) technicians performed this test at the module cabinet
located in the relay room one floor below the control room. The
first portion of the test required that the fuses be pulled on the
electrical control power to the PORV making it inoperable. This
action invoked Technical Specification 3.1.12.3 requirements that
the associated block valve be closed within one hour of the PORV
being declared inoperable. This one hour time clock requirement was
- ; ;, b ;. t r. t; i ..;
! m ..r.'r 4 ct I t 4 5 r. . r~ .
As one of the technicians was increasing the test voltage setting on
the equipment used in conjunction with this surveillance the control
room operator and the NRC shift inspector noted an unexpected low
spike on pressurizer level channel 1 in the control room. The low
spike was sufficiently large to cause the low pressuriser level
annunciator to actuate. The shift supervisor and the technicians
reviewed the wiring logic diagrams and determined that the
prescribed test sequence should not affect pressurizer level
_ _ _ _ _
.
31
.
,
instrumentation. The IEC technicians per'formel the steps again and
were able to repeat the spike on the pressurizer level channel 1
instrument. The shift supervisor,then directed that pressurizer
level channel 3 be selected. The technicians performed the steps
again and this tine they had no effect on the pressurizer level
channel that was selected. The shift supervisor then gave
permission to continue with the surveillance test. The effect of
the PORV-calibration check on pressurizer level was not completely
resolved at that time, only to the point of licensee supposition.
that a loose wire existed in the'same cabinet that was being worked
on.
The I&C technicians successfully parformed the surveillance
procedure up to the point of checking the trip (opening pressure)
setpoint, which was found to be within technical specification
tolerance (2450 1 25 psig). Before starting the portion of the
procedure associated with checking the reset (closing pressure)
setpoint, the technicians determined that the procedure could not be
performed as written and generated an exception sheet. The
technicians discussed the exception sheet with the shift supervisor
who concurred with the noted exception. He gave them permission to
perform the steps in the corrected sequence as described on the
exception sheet. Later, senior day shift I&C technicians determined
that the two technicians had misread the procedure.
The two technicians then obtained reset setpoint voltage readings.
The value (2438 psig) obtained was out of tolerance high (2400 1
6.25 psig). This value would allow the PORV to be able to ressat
after lifting at a high pressure, but the setting would cause the
PORV blowdown time to be shortur. The technicians generated a
deficiency sheet addressing the noted out-of-tolerance value for the
PORV reset pressure. The technicians brought the deficiency to the
shif t supervis or's attention, 'and af ter discussing the findings,
permission van given to recalibrate the setpolat.
In the meantime the shift supervisor, because of the technical
specification one-hour time clock requirement, directed the block
valve (RC-V-2) to be shut. This was logged in the shift foreman's
log as occurring at 2:37 a.m.
The I&C technicians, however, were unable to recalibrate the reset
setpoint, and they discussed this problem with the shift supervisor.
The shift supervisor directed them to return all calibrated
adjustment device values back to where they had found them prior to
,
,,
. . *
. . "r , , , g ; g
- J ., c # g( .=
/- r s,( g,;
test equipment ano close the cabinets., Tne surveillanct was
terminated and would be turned over to the day shift and more
experienced I&C technicians. At 2:52 a.m., as recorded in the shift
foreman's log, the PORV fuses were installed and the block valve was
opened. The shift supervisor declared the PORV to be operable at
'
that time.
At approximately 7:30 a.m., the NRC inspectors requested to see the
documents associated with the surveillcnce. The NRC inspectors were
__ _ . _ . - _ - _ - - - .- ._- - .-- . _ - _ , - - - ___ . -, _ -
._
.
32
directed to the senior day shift I&C technician who was following up
on this matter. At that time, the original surveillance procedure
could not be found, but the original exception and deficiency sheets
were found in a trash can in the I&C shop by the I&C technician and
the NRC inspectors.
Based on preliminary assessment of the information known of this
matter, the inspector questioned the operability of the PORV. The
inspector discussed his concern with the plant operations manager
who stated that he considered the PORV operable; however, he
directed a bench test of the module in question to be performed
immediately to resolve the inspector's concern. The bench test
determined that both the trip and reset setpoint values were within
the allowable tolerances. The inspector acknowledged that the PORV
was operable and had no further questions about the operability of
the valve.
While performing the bench test, the licensee contacted one of the
two technicians to determine the location of the original
surveillance procedure. At 10:30 a.m. the licensee was able to
locate the original surveillance procedure and reported that it was
on a desk in the I&C shop. In addition, later that day, SP
1303-11.45 was properly performed and reconfirmed that the PORV
t setpoints were correct.
The dayshift I&C technicians reported that the surveillance was
performed in error during the midshift because the technicians did
not correctly perform step 8.1.8.1 of the procedure which clarified
where voltages were to be read for a proper calibration check.
5.2 Scope of Review
The inspectors reviewed the incident on the apparent improper
performance of the PORV surveillance and the licensee's review of
this matter to determine the following items.
-- details regarding the cause of the incident and the
chronology
-- consistency of licensee actions with license requirements,
approved procedures, and the nature of the incident
-- proposed licensee actions to correct the cause of the
incident
Tne inspectors' review of the surveillance activity incAudes
discussions with cognizant licensee personnel and review of the
following documents.
-- Surveillance procedure (SP) 1303-11.45, Revision 5,
September 3,1985, "PORV Setpoint Check"
-- SP 1303-11.45, partially completed procedure from the
midshift on October 25, 1985
- - - _ _ _ - - - - _. . _ - . _ _ -
-- _
_ . _. . - ___-- - - _ . . - . _ _
. -
33
s
--
Exception Sheet E-1 to SP 1303-11.45, dated October 25,
1985
--
Deficiency Sheet D-2 to SP 1303-11.45, dated October 25,
1985
--
(Draf t) Plant' Incident Report No.1-85-13
--
Shift foreman log and control room operator log for
October 25, 1985 -
The inspectors also accompanied licensen personnel while they
performed the bench test of the PORV reset value. ,
5.3 Licensee's Review / Findings
During the morning of October 25, 1985, the TMI-1 Restart Staff
expressed concern regarding the apparent poor document control
practice of the exception and deficiency forms being thrown away and
the relatively poor performance on the completion of an apparently
routine calibration check. The licensee immediately dedict.ted two
senior knowledgaable individuals to independently review the event
and resolve the staff's concerns. Their review included interviews
with personnel involved and a review of the applicable logs.
reconstruction of the event chronology was generated as part oi i.ne
review. In addition, the licensee convened the Plant Review Group
to review the data to determine if the licensee was proceeding in a
correct manner with respect to the operability question of the PORV.
Although plant management had already concluded that the PORV was
operable, as an independent verification the licensee stopped
scheduled maintenance testing and performed a bench test of the PORV '
module in order to be responsive to the NRC concerns. The bench
test was quickly able to determine the operability of the PORV. In
addition, the licensee conducted an immediate search to locate the
missing surveillance procedure.
Subsequently, the licensee decided to develop a plant incident
report (PIR) as the mechanism to capture the information and to
disseminate lessons learned. Based on their review, as stated in
the PIR, the licensee' concluded the actions of the shift supervisor
were correct and in accordance with the technical specifications.
The shift supervisor" properly directed and controlled the events in
accordance with applicable facility procedures. All independent
reviews performed, including the Plant Review Group review and
' *
r e:1 - - ? t ' i m.- - .-hnt r.r : -r : u u- ' -
---.'
responsibilities, aid not uncover any significant safety concern.
The PORV was considered operable by the licensee at all times during
this event, except during actual surveillance testing.
With respect to discarding the exceptica and deficiency sheets, the
licensee's review was unable to determine how this occurred or who
discarded them. The licensee, however, concluded e. hat there was
(
>
,
k
1
34
l
y i
l
in place, as part of their administrative controls program, various
checks and balances that would have identified that the sheets were
missing. The surveillance procedure coordinator is specifically
tasked with reviewing all surveillance packages for completeness.
In addition, the noted deficiency and exception were described on
the shift turnover sheet which would trigger identification of the
problem to I&C personnel from the operations department.
Also, the licensee concluded that surveillance packages should
,
remain together at all times.
3
The licensee found that the shift supervisor could have asked more
'
probing questions associated with the noted exception sheet
-
generated by the two technicians. It was determined that the two
' technicians had never performed this test before and had misread the
procedure. If the shift supervisor had asked more questions,
misreading of the procedure may have teen identified. The procedure
as written was correct and properly obtained the required data. The
data obtained by the technicians for the PORV reset pressure setting
was not actually the required reading due to improper test
connections being used. These test connections were not the
g
+
required test connections specified in the written surveillance
g procedure. The surveillance that was performed on the dayshift
verified that the procedure could be performed as written and that
The licensee plans to review the event with all personnel who may be
involved with official facility surveillance records. The
requirement to maintain and preserve legal records will be restated.
5.4 NRC Staff Findings
The licensee was responsive to NRC concerns and their actions were
timely and provided sufficient information to permit the concerns
associated with PORV operability to be resolved immediately.
I Although the shift supervisor could have been more inquisitive,
l especially on the rather routine surveillance, the shift
supervisor's action on the operability of the PORV was technically
correct and he complied with technical specifications. The shift
,
supervisor could have better substantiated by documentation his
reasoning on the operability of the PORV. Also, the inspector
reviewed and concurred with the findings in the licensee's plant
incident report.
!
l With respect to the documentation control problen, licensee
personnel did not maintain control of the surveillance package in
that the exception and deficiency forms were separated from the
! surveillance procedure, contrary to AP 100lJ provisions, and
j personnel were careless by either discarding the forms or not
l providing enough attention to detail to assure the completed package
l was retained.
!
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35
It is merely speculative as to whether or not Technical Specification 6.10 requirements to maintain original plant records
would have been adhered to since that issue was dependent on whether
or not the licensee's review process would have identified the
missing records (E&D forms). Since the surveillance procedure had
not been discarded, it is likely that the exception and deficiency
sheets would have been identified as missing. However, this may not
have occurred in time for the records to be retrieved from the
trash. The licensee then would have had to reproduce a
reconstructed record which would be a violation of TS 6.10.
From our independent review of this matter, the inspector concluded
there was no apparent motive to cover up the event. The E&D forms
were in an obvious place -- the trash can in the I&C shop, which was
not a place one would discard a record if one were trying to cover
up the event. Further, three other records of the event were
retained, i.e., the completed procedure and the control room
narrative logs. Further the apparently adverse test results did not
reflect an immediate need to shut down the facility.
A review of the exception and deficiency sheets (required by AP
1001J) indicated that the questions on the form were not clear as to
the intent of each question. In response to one of the questions on
the deficiency D-2. the shift supervisor marked "yes" indicating
that the deficiency (lack of proper reset value for the PORV)
reflected a failure to meet TS acceptance criteria. However, the
shift foreman's log reflected that the shift supervisor determined
that the PORV was operable without details of how he came to that
conclusion. (It is well recognized that a specific TS LCO alone
does not determine operability because the specific TS must be
reviewed in conjunction with the TS definition of operability, TS 1.3.) Licensee managers reported that shift supervisors were
instructed to mark yes to the above noted question when the more
restrictive criteria of the applicable surveillance procedure could
not be met. The inspector noted that no provisions then exist on
the E&D form to determine operability of the surveillance component
and that it would appear that the shift supervisor did not
adequately resolve the deficiency before declaring the component
The problem was evident upon review of the computerized outstanding
E&D list in which a number of deficiencies were listed; but, upon
closer review, one found procedural, editorial, or updating
problems; not TS compliance or operability problems. The licensee
acknow'cdref
. this situt i:e c.f aprerf :: reciew * .i st a tier.;
with submitting a report on this matter to NRC Region 1. Inis is
unresolved pending completion of licensee action to assure that
surveillance test exceptions / deficiencies are appropriately reviewed
for operability, TS compliance, reportability, and pending the
submittal of a report to the NRC on the incident. Further licensee
corrective action for this incident will be reviewed in a future
inspection (289/85-25-06).
- -_ _ -
36
5.5 Conclusions
The licensee's initial and followup actions were responsive to the
NRC concerns. The PORV was always operable. Licensee operators
maintained the plant in the mode which they considered to be safest.
No motive for wrongdoing in discarding the deficiency and exception
sheet was noted. Existing documentation and handling measures for
surveillance test exceptions and deficiencies were considered to be
poor and warrant improvement.
6. Nuclear Safety and Compliance Committee Performance
6.1 Review
By Commission Memorandum and Order CLI-85-2, dated February 25,
1985, the licensee was required to maintain an expanded Board of
,
Directors and a Nuclear Safety and Compliance Committee (NSCC). The
committee is to have a staff of its own and is designated to monitor
the operation and maintenance of the GPU systems nuclear units with
specific attention to adherence to procedures and license
requirements. This requirement was restated a2 restart condition
1.t by NRC letter dated October 2, 1985.
The NSCC of the GPU Board of Directors was established on February
23, 1984. The committee consists of three outside members of the
GPU Nuclear Board of Directors. This committee has established on
the TMI-1 site a staff consisting of a staff director and three
members. This staff has been established to assist the NSCC in
accomplishing its mandate. The staff activities are governed by
NSCC staff guidelines.
During this inspection, the activities of the TMI-1 NSCC site staff
were reviewed. The on-site staff performs evaluations in accordance
with a six-month activity schedule which has been approved by the
NSCC. The current activity' schedule (July to December 1985)
,
provides for monitoring in the following areas.
Operations
-- monitor conduct of operations by ongoing in-plant
observations
-- evaluate normal and emergency operating procedures
-- r r ".: r c : . . . I r ,cc v. d i t c r e u 3
-- operations surveillance
-- radioactive waste operations
Maintenance
-- system maintenance and testing, including:
_ - _ _
. . _ .
37
--
containment
--
reactor pr<ssure boundary
--
maintenance of EQ components
--
restart activities
--
Davis-Besse lessons learned
--
control of maintenance
--
corrective maintenance reports to )(C
--
planning and scheduling (evaluate outage p-eparations)
--
response to NRC and INPO findings
Training
--
maintenance training
--
STA training
--
simulator instructors
--
INPO accreditation
Licensing
--
evaluate LER/ PRE (Licensee Event Report /Potentially
Reportable Evnnt Reports)
--
action item t~acking
--
preliminary safety cencerns
Radiological Control
--
contaminction control
--
radiation awareness reports
-
Chemistry
--
monitor enemistry dcpartment operations
--
chemistry procedures
Technical Functions
--
operating experience and assessment overview
- -. - - .
-_
..
- .- - . .. - - _ _ . -
38
Safety Committees
-- GORB
--
plant review group
--
10SRG
--
other
Quality Assurance
-- evaluate corrective action systems (QDRs, MNCRs, Audits.
LER followup, etc.)
--
monitor exercises and drills
Plant Engineering
-- overview of organization and responsibilities
NSCC Requests
-- observations meeting
--
Davis-Besse incident
-- biennial procedure review followup
--
plant incident reports
--
procedure standardization
-- MORT training
-- NSCC semi-ennual report
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The following evaluation reports of evaluations conducted as
described in the activity schedule have been issued since January 1,
l 1985. -
! -- THI-R-85.001, Instructor Training and Qualification, April
. ??e-
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l
-- TMI-R-85.002, Evaluation of Control Room Audits, March 15,
1985
-- TMI-R-85.003, Procurement and Control of Parts, Materials,
and Services, March 15, 1985
-- TMI-R-85.004, Processing of Design Change Packages, March
25, 1985
-- THI-R-85.005, Control of Special Processes, March 29, 1985
l
__
39
--
TMI-R-85.006, Investigation into the Use of Inappropriate i
Welding Procedures !
-- TMI-R-85.007, Instrument Calibration Stickers, May 21,
1985
-- TMI-R-85.008, Training Document Control, Records and
Records Retention, April 17, 1985
--
THI-R-85.009. Training Examination Control Process, April
30, 1985
--
THI-R-85.010, Normal and Emergency Operating Procedures,
May 6, 1985
--
TMI-R-85.011, Control of Measuri.g and Test Equipment, May
21, 1985
-- THI-R-85.012, Evaluation of the Control of Equipment
Status, May 23, 1985
-- TMI-R-85.013, Evaluation of Emergency Preparedness, June
20, 1985
--
THI-R-85.014, Review of Independent Onsite Safety Review
Group (10SRG), July 29, 1985
-- TMI-R-85.015, Review of Potential Safety Concerns and
Potential Reportable Events, September 5, 1985
--
TMI-R-85.016, Evaluation of Training Program Development
Approval and Review
The inspector also reviewed the following NSCC documentation.
--
monthly reports of NSCC staff activities for the months of
July and September 1985
-- minutes of NSCC-NSCC staff meeting conducted July 23, 1985
- --
Nuclear Safety and Compliance Committee report No. I to
the GPU Nuclear Board of Directors, October 15, 1984
--
Nuclear Safety and Compliance Committee Report No. 2 to
- '
the C7. %::1. .ir ! . irc :: - s. : *'. :~
.
--
draft Nuclear Safety and Compliance Committee staff
semi-annual report for the period April 1, 1985, through
September 30, 1985
A number of questions developed during the review of the above
documents. These were discussed with NSCC staff members as follows.
-. . ._
- 40
- --
The activity schedule provides for a significant amount of
time to be spent evaluating operations and maintenance,
yet no evaluation reports are issued which discuss these
areas.
The staff stated this time is devoted to the routine
observations of operations and maintenance. If matters
which require further staff evaluation were identified,
results of these evaluations would be documented in
evaluation reports.
--
The monthly reports discuss matters in which the staff is
involved which are not documented in evaluation reports.
These are activities in which the staff has been involved
during routine observations but not to the extent that an
evaluation report is appropriate. The monthly report does
- provide the committee with some information on these
topics. If the committee feels more information is
necessary, they would request it from the staff.
--
It appears not all findings and recommendations which
appear in evaluation reports are included in the NSCC's
+
semi-annual report to the board. How are these
transmitted to the site or sites?
One method by which these are transmitted is during
scheduled observation meetings with the committee, the
committee staff and senior GPU management. There may be
other methods of which the staff is not aware.
--
Is there routine followup to implementation of findings
and recommendations?
There is no formally established planned followup to
findings and recommendations known to the NSCC staff.
--
Monthly reports discuss trending of certain data. What is
being trended by the staff?
The following is being trended:
--
unit availability -
--
' .11 r-te
.
--
audit findings (QA)
--
radiological data
--
injury rates
--
iodine ratio
-- - - - __
- . . - . _ . . . -
41
--
open job tickets
--
Are activities at Parsippany also evaluated?
Activities at Parsippany are also evaluated by the staff.
--
How frequently are NSCC and NSCC s.aff meetings held?
These meetings are held monthly and generally last over
six hours each. These meetings provide far a major
exchange of information between the committee and the
staff.
6.2 NRC Findinas
The requirement that an NSCC with an independent staff be maintained
to monitor the operation and maintenance of TMI-1, with specific
attention to adherence to procedures and licensee requirements is
being met. Staff guidelines have been prepared which describe the
staff activities which are to be performed in order for the
committee to perform its task. These guidelines are being adhered
to. A staff, which has appror.imately 80 man years of nuclear
experience in various disciplines, has been established at the THI-l
site to perform evaluations. Based on discussions with staff
members the committee appears to stay well informed of site
activities and staff findings both through the receipt of staff
reports (semi-annual report to NSCC, monthly report to NSCC, and
specific evaluation reports) and through monthly meetings with the
staff.
Staff evaluation reports and semi-annual reports to the committee
are detailed and reflect adherence to a preplanned schedule. The
committee, in addition to approving a staff activity schedule,
frequently makes specific requests for evaluations or other actions
from the staff. There does not appear to be any formal followup by
the staff as to the disposition of evaluation findings and
recommendations.
The committee's evaluation and disposition of staff findings and
recommendations other than those formally transmitted by reports to
the GPU Nuclear Board of Directors is beyond the scope of this site
inspection. This area is unresolved pending NRC Region I additional
~
review of NSCC activities (289/85-25-07).
t.1 C an ?us i c-
The licensee is meeting the requirements of restart condition 1.t to
retain the NSCC. Additional NRC staff review will be needed to
evaluate the effectiveness of the NSCC.
42
7. Administrative Control Implementation
7.1 Review
The inspectors reviewed selected TMI-1 Administrative Control
Procedures to verify that APs were properly implemented by licensee
personnel.
The selected procedures reviewed included:
-- AP 1002, Revision 36, October 14, 1985, " Rules for the
Protection of Employees Working on Electrical and
Mechanical Apparatus";
--
AP 1036, Revision 6 February 104 1985, " Instrument
Out-of-Service Control";
--
AP 1037, Revision 4, January 3, 1985, " Control of Caution
and DNO Tags"; and,
--
AP 1063, Revision 4, August 19, 1985, " Reactor Trip Review
Process."
The specific scope and findings related to each of these areas are
addressed below.
7.2 Rules for the Protection of Employees Working on Electrical and
Mechanical Apparatus
The stated purpose of AP 1002 is to provide methods to insure the
safety of personnel who may be required to work on or around
electrical and mechanical apparatus under the jurisdiction of TMI-1.
The apparatus covered by the procedure may or may not be
radioactive. The procedure is also intended to help assure that
equipment tagging and alignments are consistent with nuclear and
equipment safety concerns. As stated further in AP 1002, the
,
detailed procedure provides a step-by-step method for the electrical
and/or mechanical isolation and control of equipment of which
maintenance, inspection, troubleshooting or testing is to be
performed.
The inspector reviewed the detailed procedures specified in AP 1002
and verified that adequate controls were in place for-awitching and
tagging operations including appropriate requirements for proper
rmz ' n to be ccr.fu::ed p:ic: : rcr ~irr ( r.'; r .: frer e.rvitt. r
however, the inspector noted that the control room operator assigned
to switching and tagging activities could approve a tag even though
he may not be certified as a switching and tagging initiator. The
inspector noted that this apparent inconsistency was allowed by
procedure and the number of control room operators not qualified as
switching and tagging initiators was minimal. Licensee
.
e- -g--, . ~ - . - - - . - ,,r . ,.-. .._ , , . , - - _ - . , . -, -.
. _
43
.
representatives stated that their certification practices would be
reviewed for appropriate followup actions, and the inspector had no
i further questions regarding this matter.
In addition to the above procedure review, the inspector randomly
selected several active switching and tagging sheets and verified
their accuracy. The inspector also determined that the switching
and tagging sheets correctly reflected what tags were posted in the
plant.
The inspector concluded, based on this review, that the licensee's
switching and tagging prcgram and procedures were properly
controlling the removal and return of equipment that was required to
be tagged out. The comments noted by the inspector were considered
to be of a minor nature.
7.3 Control of Caution and Do-Not-Operate Taas
The AP 1037 describes the purpose and control of caution and
do-not-operate (DNO) tags. Caution tags are used as an information
tag only; not.as safety tags for protection of personnel. A caution
tag is to be attached to a component, control switch or other device
to indicate an off normal condition or to caution personnel to a
specific condition which must be satisfied prior to using the
component or device. A do-not-operate tag, which is primarily used
for equipment protection may be used in place of a caution tag
particularly when used in environments where the caution tag may
easily deteriorate under extended use.
The inspector reviewed the requirements related to caution and
do-not-operate tags, as specified in AP 1037, and determined that
the guidance appeared to provide effective administrative controls
for using these tags. In addition, the inspector reviewed the
caution and do-not-operate tag log books and selected tags in use,
i Based on this review, the inspector noted only minor potential
administrative problems. The procedure established no policy on
when to consolidate caution tag log sheet entries, and the operator
cannot tell whether a log sheet is removed or lost from the note-
book. Also, AP 1037 states that upon removal of a do-not-operate
tag, the time (as well as other items) is to be filled in on the log
,
I
! sheet; however, the log sheet does not include a place for recording
time. The inspector discussed these observations with licensee
representatives and had no further comments regarding-this matter.
r_
-
l
,4 y e - -, - _- q . . . - r - - - ; - r.
___
The stated purpose of AP 1036 is to describe the method of control
of read out devices which become inoperable or are strongly
! suspected of being inoperable such that they are marked, documented
! and controlled until repair is affected. The procedure applies
principally to the control of out-of-service instruments and read
out devices which are required by the technical cpecifications. It
applies to meters, gauges, amplifiers and recorders when they become
i
1
-
, , . - _ . , _
. - . .--
,
44
-f
inoperative or are displaying what appears to be incorrect
information.
The inspector reviewed this procedure and verified that a log was
being maintained of out-of-service devices, the log reflected actual
equipment status, and out-of-service equipment did not or would not
have an adverse affect on safe plant operations.
The inspector noted that the number of pieces of equipment
out-of-service was minimal. Equipment that has been out of service
for extended periods generally was minimal and had no effect on
plant operation. Several old out-of-service stickers were still in
effect; two since 1977, two since 1981, five since 1983 and five
since 1984. However, the average length that a major piece of
equipment would remain out of service was short. From the review of
the log entries and selected stickers the inspector determined that
the lictusee's program for control of out-of-service instruments was
being implemented.
'
7.5 Reactor Trip Review Process
The inspector reviewed AP 1063 to ensure that the procedure required
the gathering and retaining of key plant parameters and plant
records that would identify significant changes and trends of plant
parameters that may be indicative of plant performance problems and
that the procedure required the necessary safety review and analysis
to be performed to ensure the plant could properly restart. In
addition, the procedure was reviewed to ensure that noted problems,
if any, were properly characterized, tracked and resolved, if
necessary, prior to restart.
Implementation of this procedure was verified as noted in paragraph
3.4. The inspector reviewed the data generated to support the post
trip review. The inspector determined that the major and
significant parameters were being retrieved and recorded. The
procedure was structured in a manner that allowed the review group
to smoothly move through the checklist in a timely manner. The -
'
licensee did note several minor administrative problems that need to
be reviewed but which had no significant impact on the overall
' '
objective of the procedure. The checklist had the necessary
provisions to cause independent reviews to be performed to resolve
identified inconsistencies in plant response. Overall, the
'
procedure was determined to be adequate.
'
.. .
The administrative procedures described above were technically
adequate although they could be improved to enhance effectiveness.
In general, these procedures were properly implemented.
.
- , - . , . , , - - . - - - - - - - - , - - - - - - - - - -r- - - , - - - , - , , - - , - - - -- -
, - , - -
- - - - - -- - m. .- ,n n- . - , . - , - - -
__
'
45
8. Exit Interview
The inspectors discussed the overall inspection scope and findings with
licensee management at the exit interview conducted on October 25, 1985.
The following licensee personnel attende1 the final exit meeting.
D. Carl, Review Program Coordinator, TMI-1
J. Colitz, Plant Engineering Director TMI-1
S. DiVito, Supervisor Design and Drafting - THI, Technical Functions
T. Hawkins, Manager, TMI-1 Startup and Test, Technical Functions
H. Hukill, Vice President and Director, TMI-1
C. Incorvati, TMI-1 Audit Supervisor, Nuclear Assurance
M. Nelson, Supervisor, Review Program, THI-1
S. Otto, TMI-1 Licensing Engineet. Technical Functions
L. Ritter, Administrator II, Plant Operations, TMI-1
M. Ross, Manger, Plant Operations, TMI-1
C. Shorts, Manager Technical Functions THI-1. Technical Functions
D. Shovlin, Manager, Plant Maintenance, TMI-1
P. Sinegar, Administrator II - Maintenance, THI-1
H. Snyder, Preventive Maintenance Manager, THI-1
R. Toole, Operations and Maintenance Director, THI-1
The exit meeting was also attended by Ajit Bhattacharyya, a nuclear
engineer 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.
There was an interim exit on October 24, 1985, with the Nuclear Safety
.
'
and Compliance Committee Staff members (Mr. E. Hammond, et. al.) to
discuss the results of the inspection on their activities.
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 3.2.1, 3.2.4, 3.2.5, 3.2.6, 4.2.3, 5.4, and 6.2.
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EDO PRINCIPAL CORRESPONDENCE CONTROL
- ------------- - - - - - -
FROM: DUE: 12/27/85 EDO CONTROL: 001245
DOC DT: 10/22/85
JANE LEE FINAL REPLY:
ETTERS, PA.
TO:
COMM. ASSELSTINE
FOR SIGNATURE OF: ** GREEN ** SECY NO:
DESC: ROUTING:
TMI " COOLING TOWER DRIFT"
DATE: 12/11/85
ASSIGNED TO: M
'
CONTACT: M ANYIT U
i
SPECIAL~ INSTRUCTIONS OR REMARKS:
A SHORT ANSWER IS IN ORDER.
TAREHM
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'
NRR RECEIVED: 12/11/85
ACTION: egGPL4: MIRAGLIA_ p[de7 4-
ROUTING: DENTON/EISENHUT
PPAS
M0SSBURG
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