ML20237H879
| ML20237H879 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 08/10/1987 |
| From: | Baunack W, Conte R, Dante Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20237H859 | List: |
| References | |
| 50-289-87-11, NUDOCS 8708170394 | |
| Download: ML20237H879 (33) | |
See also: IR 05000289/1987011
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
l -Docket / Report No. 50-289/87-11 License: DRP-50
. Licensee: GPU Nuclear Corporation ,
P. O. Box 480
Middletown, Pennsylvania 17057 ..
Facility: Three Mile. Island Nuclear Station, Unit 1
Location: Middletown, Pennsylvania
Dates: May 29 - July 9, 1987
Inspectors: D. Coe, License Examiner, Region I (RI)
R. Conte, Senior Resident Inspector (TMI-1)
D. Johnson, Resident Inspector (TMI-1)
S. Peleschak, Reactor Engineer, RI
Reporting jj j
Inspector: Mft .MV g,7
>
D.~ Johns n, Re ident Inspector
Reviewed by v>v- -
1/7/J7
R. Conte // enior Resident Inspector Date
Approvedbh: ), u (L4ws- /8/O
W. Baunack,- Acting Chief Da'te
Reactor Section No. 1A
4
Division of Reactor Projects
Inspection Summary:
The NRC resident staff conducted safety inspections (210 hours0.00243 days <br />0.0583 hours <br />3.472222e-4 weeks <br />7.9905e-5 months <br />) of power
operations and the transition into and out of the letdown cooler replace-
ment outage, focusing on operator performance, including-event response.
The following events were reviewed: letdown pre-filter noble gas
release; reactor trip of June 12, 1987; and, reactor protection system
(RPS) actuation during reactor startup. Items reviewed in the plant
operations area were: reactor coolant system leak rate, reactor shutdown
for letdown heat exchanger replacement, letdown heat exchanger problems,
and plant shutdown and startup. With respect to system operability, the
following items were reviewed: nuclear service river pump 1A overhaul
and spurious actuations of the control building chlorine detection
system. Licensee action on past inspection findings was also reviewed.
A review of the implementation of the fire protection program was also
conducted.
8708170394 870811
0 ADOCK 05000289
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Inspection Results:
No violations were identified; five. items reviewed in the course of the
inspection remain unresolved. One item concerned problems associated with the
high chloride levels in the reactor coolant system (RCS) identified during the
outage. This will require NRC staff review of licensee's evaluation of addi-
tional chemistry samples. The second item concerns the review and approval of
Technical Specifications Change Request (TSCR) No.172 for the reorganization
of the licensee corporate organization. The third item concerns the repeated
spurious actuations of the new chlorine detection system which actuates pro-
tective actions for the control building ventilation system. A licensee-
identified violation discussed during review of the fire hazards analysis will
require additional lice.isee action to get the appropriate Fire Hazards Analysis
Report (FHAR) exemptions. The last item concerns the operability of NI-9, a
source range detector for the remote shutdown panel. Corrective actions to
repair this detector and establish requirements for its operability are yet to
be determined.
The transitions into and out of the letdown cooler replacement outage went
relatively smoothly with no major equipment problems. Operator performance
problems appear to be isolated cases and are being dealt with by licensee
management.
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_ TABLE OF CONTENTS
Page
1. Introduction and Overview. . . . . . . ........... 2
2. Plant Operations . . . . . . . . . . . . . . . . . . . . . . 2
3. Maintenance / Surveillance - Operability Review. . . . . . . 10
4. Event Review . . . . . . . . . . . . . . . . . . . . . . . 13
5. Fire Protection Annual Review. ..............19
6. Licensee Action on Previous Inspection Findings. . . . . . 24
7. Exit' Interview . . . . . . . . . . . . . . . . . .. . . . . 27
8. Attachment 1 - Activities Reviewed
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DETAILS
1.0 Introduction and Overview
1.1 NRC Staff Activities
The overall purpose of this inspection was to assess licensee activities
during the power operations and cold shutdown modes as they related to
reactor safety and radiation protection. Within each area, the inspectors
documented the specific purpose of the area ~under review, acceptance
criteria and scope of inspections, along with appropriate findings / con-
clusions. The inspector made this assessment by reviewing information on
a sampling basis through actual observation of licensee activities,
interviews with licensee personnel, measurement of radiation levels, or
independent calculation and selective review of listed applicable docu-
ments.
On June 19, 1987, a resident inspector also participated in a licensee
meeting with NRC: Region I staff to discuss licensee's tentative plans to
shift to a site emergency plan instead of one for each unit. The licensee
explained that plant conditions at TMI-2 do not warrant a specific plan.
For an event at TMI-2, the combined (site) plan would be oriented toward
technical problems being resolved by TMI-2 personnel, while TMI-1 would be
responsible for overall emergency plan implementation such as off-site
notification or recall of plant personnel. A separate meeting summary
will be documented by NRC staff.
1.2 Licensee Activities
During this period, the licensee operated the plant at full power, except
for a two-week shutdown to replace the letdown heat exchangers. The
reactor was shut down on Friday, June 11, 1987; and, during the shutdown
at approximately 11 percent power, the reactor tripped due to reactor
coolant system (RCS) high pressure (see section 4). The plant was
restarted on Friday, June 26, 1987, and ended the period at full power.
The problem with Once-Through Steam Generator (OTSG) tube fouling was not
as evident as prior to the shutdown. OTSG 1evels wer- somewhat lower
after startup, especially in the "B" 0TSG. Details concerning the letdown
heat exchanger leaks are discussed in paragraph 2.2.1.
2.0 Plant Operations
2.1 Criteria / Scope of Review
The resident inspectors periodically inspected the facility to
determine the licensee's compliance with the general operating
requirements of Section 6 of the Technical Specifications (TS) in
the following areas:
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review of selected plant parameters for abnormal trends; '
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plant status from a maintenance / modification viewpoint, includ-
ing plant housekeeping and fire protection measures;
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control of ongoing and special evolutions, including control i
room personnel awareness of these evolutions;
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control of documents, including logkeeping practices;
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implementation of radiological controls; and,
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implementation of the security plan, including access control,
boundary integrity, and badging practices.
The inspectors focused on the specific areas listed in Attachment 1.
As a result of this review, the inspectors reviewed specific evolu-
tions in more detail as noted below.
2.2 Findings / Conclusions
2.2.1 Letdown Heat Exchanger Leakage
On June 3, 1987, the licensee was operating at full power with
letdown through the "1B" letdown heat exchanger (HX) MU-C-18. The
"A" letdown heat exchanger MU-C-1A was isolated due to the identifi-
cation of a leak on May 14, 1987. This leak (in the "A" HX) had
been of sufficient magnitude (estimated at 0.5 gpm) to render the
intermediate closed cooling (ICC) system radiation monitor RM-L-9
inoperable due to the meter reading being at full scale (10 E6
counts per minute (cpm)). On June 1,1987, the licensee again
experienced a leak of similar magnitude from the "B" HX, which also
produced a RM-L-9 reading of greater than 10 E6 cpm. The leak
increased during the next two days to approximately 3.3 gpm. Then, on
June 3, 1987, the leak rate abruptly increased to an estimated 30 grm.
Technical specifications prohibit operation for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
with known (identified) RCS leakage greater than 10 gpm. The
licensee shifted letdown flow back to the "A" HX and considered a
plant shutdown if the "A" HX did not show a significantly lower leak
rate. The "A" HX leak rate was subsequently measured at approxi-
mately 0.4 gpm and remained that way until June 12, 1987, when
leakage abruptly increased to 0.8 gpm. At this time, the decision
was made to shut down the plant to accomplish repairs.
During the period of time that the "B" letdown HX was in service and
leaking to the ICC system, the excess level generated in the ICC
system surge tank was being drained to the auxiliary building sump
(at approximately 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> intervals) via vent valves on the ICC
system cooler in the 265 foot elevation of the auxiliary building.
A vent on the surge tank located in the fuel handling building was
temporarily directed to an opening in the ventilation system, which
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exhausts through carbon.and particulate filters and is monitored by
RM-A-8. The RM-A-8 gas' channel indicated a slight increase during
.the time frame June 1-3, 1987, and it was-estimated that approximately 101
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curies, mostly Xenon 133 and Xenon 135, were released during this two-day
period. This release was coming mostly from the ICC system surge tank
. vent as'the,RCS was partially degassing through the leak into the surge.
tank.
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,The in'spector_ conducted independent radiation surveys of the areas
of-.the auxiliary building which contain ICC piping to confirm
licensee information. These surveys showed some readings (e.g., ICC
surge tank) to be garoximately 80 mrem /hr. Maximum readings were
30 mrem / hour on some. portions of the ICC system piping. This piping
would normally be reading less than'1.0 mrem / hour. Licensee sam-
pling of:the ICC system indicated.that total gamma activity was-
approximately 0.25 micro curies per millimeter (micro-Ci/ml). The
RCS activity was approximately 2.8 micro-Ci/ml during this period.
The inspectors discussed these changing radiological prameters for
the ICC system and the release that was occurring from the ICC
system surge tank with appropriate radiological control personnel.
Licensee radiological control personnel had evaluated these condi-
tions and concluded that they did not present a significant problem as
long-as leakage did not increase substantially. The noble gas .
release was'a small percentage of technical specification quarterly
limits. The increase in general area radiation levels in the
affected auxiliary building and fuel handling building areas was not
in areas normally traversed by personnel, except'for routine auxil-
iary operator-(AO) tours and surveys and, therefore, ALARA (as low
as' reasonably achievable) principles were not a concern. The
inspector concluded that, although this leak' rate (approximately 3.3 ,
gpm during June- 1-3,1987) was not desirable, the licensee was not
violating technical specifications and no substantial exposures would
likely result from the release or increased radiation levels.
Subsequent to the shifting of heat exchangers from the "B" to the
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"A'! on June 3,1987, the total release indicated on RM-A-8 and the
radiation levels and activity levels in the ICC system all showed
marked decreases. Although only one heat exchanger was available,
the licensee continued to operate while making contingency plans to
shutdown.
The licensee issued Special Temporery Procedure (STP) 1-87-029,
" Guidelines for Shutdown /Cooldown with Letdown Isolated," on June 5,
1987. This procedure provided guidance to the operators in the
event that leakage from the "1A" letdown heat exchanger became
unmanageable (a limit of 2 gpm was set) and both heat exchangers
were required to be isolated. The inspector reviewed this procedure
and discussed its implications with operations personnel. Although
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! shutdown without letdown is not desirable, a simulation of this
event was done on the plant simulator and showed that pressurizer
'evel would not reach high level limits during a rapid controlled !
shutdown, followed by plant cooldown. The inspector concluded again I
that even though this was not a desirable condition, it could be
managed by licensee personnel.
2.2.2 heactor Shutdown /Cooldown for Heat Exchangers Replacement
On June 12, 1987, the decision was made by licensee personnel to
shut down the plant to cold shutdown conditions to replace both
letdown heat exchangers, MU-C-1A/18. Leakage had increased abruptly
on the morning of June 12, 1987. The licensee evaluated the situa-
tion and concluded that the leak could be expected to get larger. There-
fore, since shutdown without the availability of the letdown system was
not advisable, plant shutdown for repair was the conservative
option.
The licensee employed an extra shift of personnel to assist normal
plant operations staff in conducting the shutdown. This has been
standard practice for major evolutions conducted at TMI-1. Plant
power reduction was commenced at approximately 9:15 p.m. The
inspector verified that the shutdown was being conducted in accor-
dance with Operating Procedure (0P) 1102-10, Revision 39, dated
March 20, 1987. A reactor building purge was ia progress at the
time and the inspector verified consistent and acceptable radiation
monitor reading on RM-A-2, reactor building monitor, and RM-A-9,
reactor building purge exhaust stack monitor. QA monitoring person-
nel were also present for the shutdown. The reactor shutdown was
controlled properly with no problems until just after the turbine
generator was tripped. At this time, reactor power was approximate-
ly 10-12 percent and was being controlled by the turbine bypass
valves. The feed pumps were being controlled in manual and the
operator did not maintain the proper flow to the OTSG's. The
resultant lowering of OTSG levels resulted in a high RCS pressure
condition and subsequent reactor trip (see section 4).
Overall, the cooldown was properly controlled. Based on a sampling
review, the cooloown procedure was properly followed. Operators
were particularly plotting reactor coolant system (RCS) pressure (P)
and temperature (T) within the P-T curve limits and cooldown rate
(temperature vs. time) was also plotted. The inspector noted that
the cooldown curve used was not that specified in the licensee's
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cooldown procedure, but it was a suitable equivalent.
2.2.3 Plant Heatup/ Reactor Startup
On Ju'e 25,1987, the licensee commenced plant heatup to 525 F,
after the completion of the letdown cooler replacement. The inspec-
tor witnessed portions of the plant heatup over a two-shift period
on June 25, 1987. Initial heat up operations with three RCP's in
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service were conducted smoothly with few problems. The inspector
verified proper licensee tracking-of RCS heatup rates as plant
heatup is limited to 100 F/hr. During:the heatup, the licensee
identified a high chloride (C1) concentration. in the RCS. The
chloride sample indicated approximately 0.45 ppm (p' arts per million).
The technical specification limit for critical operation is
'0.15 ppm. ' The heatup was stopped at approximately 375 F in order to
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. clean up the RCS. Maximum letdown flow of 120 gpm was established
and, 'using the installed. letdown demineralized and filtering sys-
tems, chloride concentration was lowered to approximately 0.129 ppm
I' by 5:00 a.m. on' June 26, 1987.. Plant heatup was recommenced and hot
shutdown was reached at 9:00 a.m.
Licensee representatives could not positively identify the chloride
source. One plausible explanation was related to the fact that, earlier
in the outage, high chloride concentration was detected in the "A" decay
heat (DH) loop when the plant was in cold shutdown. Residual chlorides
that remained in the system could have leached-out of RCS metal crevices
during the heatup. The licensee established some data which'showed
that lithium eJditions for pH control would temporarily cause the
chloride concentration to increase. The source of the chloride
. intrusion.into the decay. heat system was also unknown.
The leaching-out process is'a plausible explanation for the chloride
increases when heatup commenced and proper chemistry was being
established. Final chloride concentration was reduced to less than 0.1
ppm. The licensee chemistry department is still studying the problem and
has sent several RCS samples off site to an independent lab for
analysis. The licensee intends to report the results of the inves-
tigation when completed. The inspectors will review the results of
that investigation in future inspections. This item is unresolved
.(289/87-11-01).
Just prior to heatup, the licensee conducted a special test, Special
Temporary Procedure, STP 1-87-033, to adjust the intermediate closed j
cooling system flow in preparation for changing to a parallel cooler '
arrangement for the letdown heat exchangers. Parallel cooler
operation, in addition to modifications in the control circuitry for ,
the cooler outlet isolation valves, MU-V-2A/B, were the changes made j
in an effort'to reduce the failures that were observed in the
letdown coolers. MU-V-2A/B now will only close approximately 10
percent during Engineering Safeguards Actuation System (ESAS)
testing and during the testing of the interlock for radiation monitor
RM-L-1. Previously, these valves would shut during the quarterly testing
of these valves. MU-V-2A/B function as the inside containment isola-
tion valves for the letdown line. The inspector reviewed the
changes to OP 1104-8, Revision 27, dated January 26, 1987, "Interme-
diate Cooling System," and OP 1104-2, Revision 61, dated January 6,
1987, " Makeup and Purification System," to verify that proper safety
evaluations were made.
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l The inspector reviewed the modification package, Safety Evaluation
(SE) No. 128965-001, to verify that proper consideration was given
to technical specification and Final Safety Analysis Report (FSAR)
requirements concerning the operation of MU-V-2A/B. This modifica-
tion was similar to the controls provided for other containment
isolation valves such as IC-V-2 and NS-V-35. The inspector verified
that the licensee was granted an exemption from the quarterly
cycling requirements of Section XI of the ASME (American Society of
Mechnical Engineers), B&PV (Boiler and Pressure Vessel) Code, for
MU-V-2A/B. This was a previously granted exemption as a result of
NRR evaluation of the licensee's submittal of their second ten year
inservice testing (IST) program.
The inspector also reviewed the completed test procedures TP 455-1
and 455-2 that verified propar operability of the modification. The
valves will still close on a valid ESAS signal as long as the new
test switches are in the normal position. The position of the
switches is administrative 1y controlled by procedure.
Also, during the heatup, an RPS actuation occurred when in shutdown
bypass conditions and the event is detailed in paragraph 4.4.
Overall, the licensee appears to have taken proper corrective action
to correct the problem with the leak development in the letdown heat
exchangers.
2.2.4 Early Criticality
At 4:35 a.m. on June 24, 1987, the licensee identified that the reactor
was critical below the specified range for estimated critical rod posi-
tion. The reactor was declared critical with Group 6 at 31 percent with
the maximum estimated critical position (ECP) at 65 percent on Group 7 and
minimum position at 54 percent on Croup 6. In accordance with facility
procedures, operators immediately inserted control rods to assure the
reactor was sufficiently shut down (1% delta K/K). Apparently, " excess
fuel reactivity" was underestimated due to depletion of lumped burnable
poison in the reactor core. Nuclear engineers processed a procedure
change to the applicable reactivity curve and reevaluated the ECP. Then
reactor startup continued without similar incident.
With the new calculation of ECP at 58 percent withdrawn on Group 6,
the minimum rod position for criticality was calculated to be 14
percent withdrawn on Group 6 and maximum was 30 percent on Group 7.
The actual critical rod position was 31 percent on Group 6. '
The resident inspectors first learned of the problem from a log
review during backshift inspections later that weekend. Initial
inspector review of the Temporary Change Notice (TCN) (No.
1-87-0143) on June 28, 1987, generated additional questions. The
TCN safety evaluation (on file in the control room) was very brief
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(handwritten with one of four lines illegible due to copying of the
original TCN) and it provided little obvious technical basis for
correcting the fuel excess reactivity term by 0.25 percent delta
K/K. During later discussions with the licensee's nuclear engineer,
it became clearer as to the basis for the above-noted change. These
discussions occurred through the week of June 27, 1987, and in a
conference call between NRR staff, Region I staff, and the licensee
on July 6, 1987. A summary of these discussions is presented below.
The licensee has been tracking the all rods out (AR0) boron concen-
tration as being consistently high above target since the beginning
of reactor core life for this cycle of operation. For the startup
on June 27, 1987, core life was seventy effective full power days
(EFPD) and the ARO boron concentration was approximately 920 ppm
(parts per million) with the target at 870 ppm. The ARO boron
concentration is a measure of the excess fuel reactivity, since the
measurement is made essentially with all rods cut o' the core and
with compensation for other reactivity terms such is " power doppler
defect" and equilibrium xenon. Surveillance Procedure (SP)
1301-9.5, Revision 22, effective March 11, 1987, " Reactivity Anomaly,"
makes the measurement and, on a sampling basis, the inspector determined
it to be technically adequate to meet TS 4.10. Similarly, the inspector
determined the technical adequacy of the ECP Procedure 1103-15B, Revision
6, effective March 13, 1987, " Estimated Critical Conditions."
These results indicated that the core is more reactive than that
reflected by the target ARO boron concentration. The target curve
is provided by the Nuclear Steam Supplier (Babcock and Wilcox (B&W))
with a target band. The above-noted results were within that band
(for 70 EFPD the band is 750 ppm to 970 ppm). Licensee representa-
tives provided two reasons for the ARO boron concentration being off
target.
There appears to be a modeling problem with lumped burnable poison
(LBP) burnout rate. The LBP is placed in a fuel assembly designed
to " burn out" during reactor operation to provide extended core life
(12 to 18 months). It has been determined at other B&W plants with
extended core life that, la % in core life, the ARO boron concentra-
tion approaches the target s ave, thus the reason for not adding a
correction factor to all tFe appropriate reactivity curves. The j
other reason provided by the licensee representatives is the buildup ;
of Plutonium (Pu-239), which adds fuel reactivity of approximately l
.26 percent delta K/K, which is not factored into the reactivity !
curves for this cycle of operation. The licensee representatives i
pointed out that incorporating this factor into the ECP would have I
resulted in achieving criticality in the calculated target band.
The inspector noted that a brief explanation of this phenomenon was l
provided on a one page SE written by the lead nuclear engineer and J
attached to a copy of the ECP calculation. The forms provided by
l the licensee's technical and safety review process procedure were
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not.directly used in this instance, but the SE appeared to be
technically sound. The inspector expressed concern that the infor-
mation was not consolidated into clear and concise presentation,
using appropriate administrative control forms, as justification to
proceed with startup. The licensee acknowledged this comment. During
the confe*ence call of July 6,1987, the licensee committed
to sending a letter to NRC staff within two weeks of that date
explaining the above in a clear and concise manner for NRR staff
review, along with appropriate corrective actions. The inspector
had no additional comments on this matter.
2.2.5 Licensee Reorganization
Dn Friday, May 29, 1987, licensee representatives announced a
reorgani::ation of GPU Nuclear, effective June 1,1987. Nine divi-
sions under the Office of the President remain; but, five of the six
corporate-based divisions changed functional responsibilities. No
changes were made to the Communications Division or the site operat-
ing divisions: TMI-1, Oyster Creek, and TMI-2.
The divisions with new functional responsibilities are as described
below. (1) A new Division of Planning and Nuclear Sefety is headed
by Dr. Robert Long, formerly Director of Nuclear Assurance Division
(NAD), a disbanded division. This new division also has the Licens-
ing Department, .formerly under the Division of Technical Functions.
(2) The Division of Administration is headed by Mr. F. Manganaro,
formerly Director of the Division of Maintenance, Construction and
Facilities. This division picks up, in part, the Training and
Educaticn Department, formerly under NAD. (3) The Division of
Maintenance, Construction and Facilities is headed by Mr. R. Heward,
formerly Director of Radiological and Environmental Controls. (4)
Another new division is the Division of Quality and Radiological
Controls and it is headed by Mr. M. Roche. This division picks up
the Quality Control function, formerly under NAD. (5) The Division
of Technical Functions (remains under Mr. R. Wilson), which essen-
tially remains in tact, except for the removal of its licensing
responsibilities as noted above.
The inspector noted that the reorganization was inconsistent with
that specified in Technical Specifications (TS) Section 6, Figure
6-1. L;censee representatives acknowledged that fact and indicated
that this change was not substantial in that the responsibilities did
not change management level positions and the operating divisions were
unaffected. Apparently no 10 CFR 50.59 safety eveluation was conducted
for this change prior to June 1, 1987, to assess whether or not a tech-
nical specification clarification was needed on a pre-implementation
basis. However, both GPUN licensing management and the GPUN President
discussed these changes with NRC Region I management on May 29. The
licensee committed to submitting a Technical Specification change by June
19. To clarify the technical specification, on June 19, 1987, the
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licensee submitted Technical Specification Change Request (TSCR) No.172 ]
to make the TS Figure 6-1 more in line with the current reorganization j
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and the question on significant safety hazard is addressed by that letter.
This area is unresolved pending NRC staff review and approval of-
TSCR No. 172(289/87-11-02).
2.3 Plant Operations Summary
Licensee management and the quality assurance department continued
their detailed attention to and involvement in plant operations.
Generally, operations were carried out formally and in accordance
with licensee procedures. The errors made by personnel resulting in
the reactor trip on June 12, 1987, and the RPS actuation on June 23,
1987, were isolated incidents of individuals not using appropriate
judgement in the conduct of their particular function at the time.
Operator action to recover from these incidents was performed
adequately.
Activities requiring safety review could have beer, enhanced with the
better use of the consolide:ed corporate policy in this area.
3. Maintenance / Surveillance - Operability Review
3.1 General Criteria / Scope of Review
The inspector reviewed activities to verify proper implementation of
the applicable portions of the maintenance and surveillance pro-
grams. This was a spontaneous review to capture ongoing activities
in the plant spaces as they occurred. The inspector used the
general criteria listed under the plant operations section of this
report. Specific areas of review are listed in Attachment 1. A
more detailed review of equipment operability was also addressed
below.
3.2 Selected Equipment Operability Review
The inspector reviewed licensee maintenance (preventive and corrective)
and surveillance activities to assure nuclear service river water pump
operability. Specifically, the inspector was to verify that:
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equipment was appropriately tagged out of service;
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procedures were being followed by maintenance personnel and the
procedures were current;
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test equipment was calibrated;
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replacement parts were appropriately noted and certified; and,
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-the maintenance history for the nuclear river water system
indicated no. major problems.
The inspector reviewed the maintenance and surveillance that was conducted
on the "1A" nuclear services river water pump (NR-P-1A). The pump was
observed by.the licensee' to.have brass filings emitting from the' packing-
- gland and this indicated ~ some problem with the bearings on the pump :, haft
and housing. The pump motor also indicated high vibration readings.
~
NR-P-1A'is a' deep shaft-type pump used to supply river water to the
nuclear service closed cooling system heat exchangers. The licensee
replaced the majority of pump components during this maintenance, inclu-
ding the submersible bowl, impeller, shaft, shaft to support column
. bearings,- and packing.
The inspector reviewed the conduct of the work as it was being accompl-
'ished, discussed the -various aspects of the repair with licensee
personnel, anrl< reviewed the following documentation associated with the
repair and testing.
--
Job. Ticket (JT) CM-855.for NR-P-1A overhaul
--
Corrective Maintenance'(CM) Procedure 1410-P-14, deep' shaft
pump (RR, NR, SR, RB) yearly overhaul.
--
SP 1300-3I A/B, Revision 25, completed June 13, 1987,'"NSRW
Pump Functional Test and Valve Operability Test."
3.3 Findings / Conclusions,
3.3.1 Nuclear Service River Water pump
Generally, maintenance personnel involved in the repair evolution
were knowledgeable of the equipment that was being repaired.- The
-inspector observed portions of the pump impeller-t bowl clearance
adjustment. This involved applying a pre-load to the shaft using a
"dillon load cell" and chain fall arrangement. The amount of
pre-load force that the maintenance personnel used was as specified
in CM Procedure 1410-P14. The inspector observed initial pump
operation and packing adjustment after the repair was completed.
Maintenance personnel used appropriate caution to ensure that the
packing was well lubricated-and that sufficient water flow was
available to prevent the packing from overheating. The evolution
.was coordinated well with operations personnel. The pump was
allowed to run for several shifts to ensure proper operation prior
to performance of the surveillance test.
.The inspector also observed the post-overhaul inservice inspection
(ISI) of the pump impeller that was replaced. Some portions of the
impeller were worn substantially and portions of the shaft'also
exhibited evidence of some wear. The post-overhaul ISI examination
of the worn parts is a licensee initiative in addition to the normal
p
t -
a
.
.- 12
l
corrective maintenance program review. This is, intended to ensure that
adverse or unexpected pump degradation'due to the harsh conditions to
which this pump is subjected will be appropriately identified and tracked
for corrective action.
Post-maintenance surveillance test results were reviewed by~the
inspector and data was verified to be within acceptable tolerances.
The inspector concluded that this maintenance evolution was conduct-
ed in accordance with appropriate maintenance and surveillance
procedures. Persennel involved were knowledgeable of the work being
done. The inspector had no safety concerns with this evolution.
~
3.3.2 Core Flooding System Valve Operability
The inspector witnessed the performance of SP 1303-11.21, Revision
7, dated December'23,1983, " Core Flooding System sives Operability
Test." Subsequently, the inspector reviewed.the i ucedure for
technical adequacy to meet the requirements of TS 4.5.2.3 for check
valve CF-V4A/B and isolation valve operability. This test also
satisfies ASME inservice testing for these valves (partial stroke
testing) as required by TS 4.2.2.
On a sampling basis, the inspector verified that the operators
properly implemented the procedure during the cooldown sequence.
. Appropriate data was recorded and it was within test acceptance
criteria.
Subsequent to the test, the inspector reviewed the procedure for
technical adequacy. The procedure met the intent of the applicable
TS.
3.3.3 Control Building Ventilation Chlorine Detector
For Cycle 6 startup, the licensee installed safety grade chlorine
(C1) detectors at the river water screenhouse (channels CE 776-1 and
777-1) and the air intake tunnel (channels CE 776-2 and 777-2). At
5 ppm (parts per million), they actuate to place the control
building (which includes the control room) ventilation system (CRVS)
into a recirculation mode to prohibit outside C1 from entering the
control room environment. Since that startup, there has been
periodic actuation of the CRVS into the recirculation mode due to
spurious high Cl detector response.
Licensee representatives similarly noticed the problem and requested
a solution from plant engineering. Cognizant plant engineers
explained that the detector is sensitive to certain environmental
conditions. Direct sunlight and heavy rainfall apparently promote
drying and saturation conditions on the probe. Chlorine detection
___ ___________
- - _ - _ _
.
13
is based on a conductivity measurement based on how much chlorine is
absorbed into the probe. Currently plant engineering is working on
a solution under Change Modification Request (CMR) No. 0820M.
During the above discussion, the inspector determined that the
licensee had instituted weekly preventive maintenance for these
problems,10-145, " Intake Chlorine Monitor Probe Maintenance." This
is apparently ineffective in keeping up with the changing environ-
mental conditions.
The inspector did not question the operability of the system.
~
In
fact, it appears to be too sensitive to changing environmental
conditions. He expressed concern for the reliability of the system
under such circumstances and when spurious actuations on a real
chlorine leak event have occurred. He also questioned operator
conditioning to the spurious actuations. This area is unresolved
pending NRC: Region I review of the licensee solution for CMR No.
0820M (289/87-11-03).
3.4 Operability Summary
Licensee maintenance management and the quality assurance department
were also involved in this area. In general, safety-related equip-
ment was operable and kept in good working order. However, the
licensee needs to resolve the problem with the Cl detection probes.
4. Event Review
4.1 Introduction and General Scope of NRC Staff Review
During this inspection period, there were several events that the
NRC staff reviewed in Lore detail. They were: the letdown
pre-filter noble gas release of May 28, 1987; the reactor trip of
June 12, 1987; and, reactor protection system actuation of June 24,
1987. In general, the following aspects were considered for each of
these events:
--
details regarding the cause of the event and event chronology;
--
functioning of safety systems as required by plant conditions;
--
consistency of licensee actions with licensee requirements,
approved procedures, and the nature of the event;
--
radiological consequences (on site or off site) and personnel
exposure, if any;
--
proposed licensee actions to correct the causes of the event;
,
I
_ _ - ._- _ __ _ _ - _ _ - -
L
.
. 14
--
verification that plant and system performance are within the
limits of analyses described in the Final Safety Analysis
Report (FSAR); and,
l
--
proper notification of the NRC was made in accordance with 10
CFR 50.72.
For each of these events, the inspector provided a chronological /
factual summary and a specific scope of NRC staff review, licensee
findings and NRC staff findings. An overall conclusion on licensee
l
, performance is also provided.
4.2 Letdown Pre-filter Noble Gas Release
At the close of the' previous inspection period, the licensee experi-
enced a small release of noble gas from the auxiliary building
during the changeout of a letdown pre-filter cartridge. This
occurred on May 29,-1987, and was noted in Inspection Report No.
50-289/87-10, but details ~ were not available at the time to allow a
proper discussion in that report.
Subsequent' investigation by the licensee'and the inspectors revealed
that a drain valve for the filter housing was left open and this
allowed water to drain to the auxiliary building sump during the
- filter changeout. Since the water was coming from the reactor
coolant system (RCS),. noble gas was released to the auxiliary
-
building and to the atmosphere via-the monitored filtered building
exhaust fans. RM-A-8 showed a-slight increase which was calculated
to be 0.0994 curies. This represents a very small fraction of the
quarterly release limits for noble gas.
The drain valve'is operated via a reach rod through the shield wall
that protects personnel from the high radiation levels present at
the filter housings. Binding in the reach rod mechanism allowed the
valve to remain partially'open when it was supposed to be shut.
This condition was corrected by licensee maintenance personnel and
the valve subsequently tested satisfactorily. The licensee has
. subsequently completed several filter changeouts with no recurrent
problems.
The inspector concluded that licensee corrective action for this
problem was adequate. The inspector had no safety concerns for this
item. The licensee is presently in the process of evaluating
ventilation flow paths and flow rates from the auxiliary building in
'an attempt to prevent any noble gas releases from spreading through
the auxiliary building when they occur.
_ _ _ _ - _ - _ _ _ _ - _ _ - _ _ -
- _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ ._. _ _ . -_ _. _ __ _ _ _ _ _ _ _
i
.
15
4.3 Reactor Trip
4.3.1 Event Chronology
At 9:20 p.m. on June 12, 1987, the licensee started a normal plant
shutdown for the letdown cooler replacement outage. At 9:42 p.m.,
operators experienced minor feedwater oscillations. At 9:51 p.m.,
the low steam level emergency feedwater (EFW) initiation function
was defeated as permitted by technical specification for this cycle
of operation when reactor power is less than 30 percent for a normal
shutdown. At 9:56 p.m., operators manually tripped the main tur-
bine. Between 9:51 p.m. and 9:57 p.m., while in manual operator
control, main feedwater flow started large oscillations and it was
eventually lost with reactor power at 10-12 percent. This resulted
in RCS high pressure and a reactor trip occurred at 9:57 p.m. when
only two-of-four reactor protection system (RPS) channels for RCS
pressure reached 2300 psig.
Once-through Steam Generator (OTSG) levels reached approximately 11
inches on the "A" 0TSG and 2 inches on the "B" OTSG. The EFW pump
start occurs at 10 inches, normally; but, since the initiation
system was in defeat, no EFW actuation occurred. Operators restored
levels in the OTSG to low level limits of 30 inches using the main
feedwater system.
Because of operator response to the low level in the OTSG's, the
startup regulating valves were opened excessively and a large amount
of feedwater was injected into the steam generators. The operato'
quickly responded to prevent an excessive cooldown rate in the RLS.
Since the reactor was already shutdown by the trip, the licensee
decided to proceed with the plant cooldown for outage preparations
and they conducted a post-trip review on June 13, 1987.
The inspectors attended that post-trip review in addition to wit- {
nessing the reactor trip, since they were on backshift coverage 1
during that weekend. )
4.3.2 Specific Scope of NRC Staff Review for the R, ;ctor Trip J
Specific to the reactor trip event noted above, the inspector
verified the below-listed items:
--
initial proper response of the plant to the post-trip window on
the pressure-temperature (P-T) plot;
l
--
personnel properly implemented ATOG procedures and prudently '
acted o, unusual conditions;
1
!
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_ _ _ _ -
i
,
.
16
l
l
--
identification of the sequential proximate causes for the trip
l
along with a reasonable determination of the root cause;
--
post-trip review was conducted in accordance with Administra-
tive Procedure (AP) 1063, " Reactor Review Process;" and,
--
no unreviewed safety issues identified in post-trip review
date.
In addition to discussions with cognizant licensee personnel, the
inspector:
--
made an independent assessment of post-trip parameter response
based on visible strip charts and indicators in the control
room shortly after the events;
--
attended the licensee's post-trip review;
--
reviewed the complete post-trip review package ( O . 87-03);
and,
--
reviewed AP 1063, " Reactor Trip Review Process" for adequacy.
4.3.3 Licensee Findings / Conclusions
For the reactor trip, listed below is a summary of the licensee-
identified problems / findings along with licensee resolutions:
(1) The cause of the trip was operator inattention to differential
pressure indicator in the main feedwater system while operating
a main feedwater pump in manual speed control. This differen-
tial pressure assures enough driving head for water to be ;
injected into the OTSG. This cause was also noted for a trip ;
in 1986. >
At the post-trip review, operations department decided to
re-review operator training for the period of low power opera-
tion with main feedwater in manual control.
The licensee operations department also issued a memorandum to
all shift supervisors stressing the need for closer cooperation
among all shif t operations personnel during these types of
plant transients to assist in preventing abnormal occurrences.
(2) One channel of source range instrumentation (NI-1) acted
erratically and sometimes failed. Based on past trips, the
problem had been traced to a faulty cable.
The outage list had replacement of new cables for both NI-1 and
NI-2. This was accomplished during the letdown cooler outage.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _
_ _ _ - __-- _
+
17
(3) Minimum pressure in a steam generator went below 925 psig (at
815 psis). By the licensee's post-trip administrative control,
this abnormality was to be independently reviewed.
The post-trip group concluded that the minimum pressure-was due
to overfeeding the 0TSG's because of operator response to the
low. level situation. It was also concluded that operator
response was good to take control of the overfeed situation and
prevent an excessive cooldown. rate'on the'RCS.
The independent review was conducted June 16, 1987, by the
Plant Review Group (PRG), which concluded that no unreviewed
safety question existed.
(4) Other minur. equipment problems were noted and they were placed
on the outage work list for corrective action.
'4.3.4 NU Findings / Conclusions
The inspector independently confirmed the licensee findings /conclu-
sions as noted above. Plant response was essentially as expected
with minor problems noted. The licensee adequately identified these
problems _and planned appropriate and reasonable action for immediate
correction and to prevent racurrence. The AP 1063 was adequate to
identify / confirm the root cause of the reactor trip and the
post-trip review was. reasonably thorough to identify appropriate
corrective actions before:startup.
Operator response to the trip and off-normal. conditions were essen-
tially consistent with facility operating and emergency procedures.
It appeared that they were conscious of and they oriented' their
" actions toward. confirming reactor shutdown. conditions and adequate
decay heat removal. Licensee action-to recover from the reactor
trip'was adequate. The memorandum noted above to enhance shift
awareness of the feedwater pump control at lower power level was
adequate. The Plant Operations Director (POD) indicated.that sufficient ,
training and procedure guidance existed to have precluded the event. '
The inspector also reviewed the procedural guidance for this evolu-
tion. The feedwater system startup procedure addresses the problem
explicitly with cautionary notes, etc. However,'the shutdown
section provides little guidance in this regard. Nonetheless, the
operators do train on this evolution frequently and they should know
what is expected of them during such evolutions. The POD acknowl-
r- edged that the feedwater pump procedure may be enhanced in the next
periodic review of that procedure.
Cont'rol of the feed pumps in manual is a somewhat difficult evolu-
tion that demands attentiveness on the part of the operator. This
!
.----------- _ _
.
- 1B
!
type of control problem has resulted in a previous reactor trip.
The inspector. concluded that this type of problem can occur based on
-the variation in individual operator skill level and it is not
considered a serious training deficiency.
The inspector pursued another apparent problem not specifically
identified as such by the licensee. The post-trip review identified
that one or two OTSG safety valves lifted.' The inspector initially
thought that to be unexpected since the initial plant power.just
prior to the reactor trip was 10-12 percent, well within the capacity
of the turbine bypass valves and the atmospheric dun'p valves.
On a reactor trip, the turbine bypss valves open at 1010 psig while
the atmospheric dump valves start opening at'1026 psig and the first
set of safety valves open at 1030-1050 psig. For this trip, the
turbine bypass valves (initially open with turbine header pressure
at approximately 875 psig) went closed on reactor trip with the
automatic change in setpoint to 1010 psig. In response to the trip,
OTSG pressure rapidly increased to the 1010 psig turbine bypass
valve setting (for trip condition). The' licensee representative
stated that actual valve response was apparently too slow to turn
~
the OTSG pressure increase and prevent overshoot into the range of
safety valve'setpoints.
The licensee representative indicated that the licensee was
re-reviewing the coordination of the valve setpoints in conjunction
with the B&W Owners Group Reassessment on OTSG safety valve chal.-
1enges (previous unresolved item No. 289/85-26-05). The inspector
had no additional' comments on this matter.
The' pre-startup RPS calibration checks showed that the two high
pressure ' channels that did not trip were in proper calibration.
Licensee representatives explained that the plant was almost recov-
ered from the feedwater oscillation that occurred just prior to the
trip. The inspector had no additional comments on the matter. )
2
i
4.4 Reactor Protection System (RPS)-Actuation i
During the heatup, as pressure was being increased to 1700 psig, the
operators were procedurally required to drive four safety rod groups to
the bottom of the core during shifting of the reactor protection system
-(RPS) out of the shutdown bypass condition. In this condition, the RPS
has reduced high pressure trip setpoints of 1720 psig vice the normal 2300
psig setpoint. In order to prevent a reactor trip, the rods must be
inserted prior to reaching this reduced setpoint, then the shift made tg.
., .
. ... - . g) .RP3 "'setpoint~s. ' The' safet~ ' groups
y ~can' then be re-withdrawn af ter
pressure is increased above 1800 psig. The low pressure trip setpoint is !
bypassed when the RPS is in the shutdown bypass mode. '
!
'
'!
_ _ _ . _ _ _ _ _ _ _ _ _ _ _
,
.
, , 19
The. operators were in the process of ' driving the last group of
safety rods (Group -1) to the bottom of ~ the core when pressure was
allowed to: increase close to the 1720 psig setpoint. As result,.the
reactor tripped on the reduced RCS high pressure trip setpoint.
Operators had been monitoring RCS pressure using the digital pressure
indication, which is not the instrument used to generate the RPS. trip
setpoints. This instrument indicated approximately-1685 psig at the
time of the trip. The relatively large disparity between pressure
indications was due to the uneven reactor coolant pump combination
-- one pump in one loop with two pumps in the other loop. It
appears that the operators had allowed pressure to increase close to
the: lower tolerance-band of the RPS pressure instrument while-
monitoring another instrument.
The licensee made the required NRC notifications-for RPS actuations
per 10 CFR 50, Part 73, and the inspector will review the resultant
Licensee Event' Report (LER) when it is submitted by the licensee.
The inspectors concluded that no particular safety concern was
generated by this RPS actuation. The licensee did not conduct a
post-trip review as their Administrative Procedure (AP).1038 only
requires a review if the reactor trip occurred at power. It appears-
that more operator attention to detail is required when conducting
this evolution. No previous startups have resulted in this type of
problem and the inspectors. concluded that this was' apparent 1,v an
isolated incident.
4.5 Event Summary
Overall, operator response to off-normal events were oriented toward
safety and in accordance with facility' procedures.
Licensee management and quality assurance department provided
substantial attention and involvement in the reactor trip and
post-trip review. Post-event reviews were reasonably thorough with.
corrective action appropriately identified, documented, and evaluat-
ed for impact on plant operations.
Plant response was as' expected. When required, safety systems
functioned appropriately. There were no challenges to the emergency
core cooling systems.
5.0 Fire Protection
5.1 Fire Protection Annua'l Review
The inspector conducted a review of the licensee's fire protection
program to verify that proper measures have been established and are
.being maintained to prevent, detect, and control fires at the site.
The. licensee's fire protection program is described in AP 1038,
Revision 13, dated January 12,1987, " Fire Protectica Program."
_ - ______ -
- . _ _ _ _ _ . . - - _ _ _ - _ _ _ _ __
.
. 20
Also, the requirements for operability / surveillance of fire detec-
tion and control equipment are delineated in Technical Specifica-
tions (TS) Section 3.18 and 4.18. The requirements for fire protec-
tion audits are contained in Section 6.5.3.1g and 6.5.3.2a/b. The
inspector reviewed these procedures and requirements to verify
proper licensee implementation of the fire protection program.
5.1.1 Audits
The inspector reviewed audits completed during the period since the
last annual review. The bi-annual audit of the fire protection
program and implementing procedure, S-TMI-86-03, required by TS 6.5.3.lg was completed on April 24, 1986. No major problems were
noted, except that the local fire company did not participate in an
on-site drill during 1985, The inspector questioned the lead fire
protection engineer as to the cause of the problem and if a problem
existed in gaining support of the local fire company. The licensee
responded that scheduling of local fire company personnel, who are
all volunteers, was difficult that year. Since that time, the local
company has participated in on-site drills. It was also noted that
the local company personnel do use the on-site facilities for their
own training and are, therefore, familiar with site practices and
configurations. This was not a concern to the inspector as on-site
participation has taken place.
The inspector reviewed the latest annual fire protection audit
0-TMI-86-09 completed October 27, 1986, which is required by TS 6.5.3.2a. Several minor discrepancies were noted but were satisfac-
torily resolved by on-site licensee personnel and documented in a
memorandum to file from the lead fire protection engineer. The
inspector had no other concerns on the completion of these audits.
5.1.2 Fire protection System Walkdowns
The inspector examined visible portions of the fire protection water
system to verify that valves were lined up in accordance with
approved system lineup procedures. Surveillance Procedure (SP)
3301-M1, Revision 28, dated April 24, 1987, " Fire System Valve
Lineup Verification," was used as a guide. No discrepancies were
noted, except that FS-V-399, the shutoff valve for the auxiliary
building 281 foot area deluge system was noted as closed when the
valve is open as the deluge station is now automatically actuated.
It was previously a manual station. An Exception and Deficiency
(E&D) sheet was properly noted and dispositioned. A Procedure
Change Request (PCR) is required to update the procedure.
The fire pump rooms were examined, along with selected post-Indicator
valves, hydrants, deluge stations, and sprinkler stations. No problems
were noted. The inspector also observed proper installation of fire
1
_ _ _ - _ _ - _ _ _ _ _ _ _ _ -
_
.
. 21
barrier penetration seals, fire detection systems, and alarms and fire
- doors. Fire extinguishers that were checked all had proper inspection
tags that indicated monthly checks were completed.
The inspector questioned the lead fire protection engineer on an
apparent discrepancy in the fire barrier penetration seal design. A
large area containing several pipes and electrical conduits was
visible in the ceiling of the 281 foot elevation of the fuel han-
dling building or the " chiller room." It appeared that this area
should have been sealed to separate the two levels of the fuel
handling building 281 foot and 305 foot areas. The licensee re-
sponded that the Fire Hazards Analysis Report (FHAR) considered
these two' locations as one fire zone and that they were protected
accordingly as described in the FHAR.
The inspector reviewed the completed surveillance file for surveillance
required by TS 4.18. The E&D sheets that were generated for the surveil-
lances were limited in number and were resolved satisfactorily. No
discrepancies in the surveillance program were noted.
The 5spector did question the licensee maintenance personnel
concerning ongoing evaluation of fire pump discharge check valves
that are being considered for inclusion in some type of preventive
maintenance program. This is a residual concern following the
damage done to the FS-P-3 building when check valve FS-V-27 failed
open (previous inspection finding 289/86-10-02).
The licensee personnel stated that they are currently evaluating
several commercially available non-destructive examination systems
that will allow check valve performance / operability determination
without disassembly. A decision on the implementation of this type
of system would probably be made within the next three to four
months. The inspector will continue to track licensee effort in
this area (289/86-10-02).
Fire brigade training and performance was not evaluated (normally a
yearly review) as extensive review of this area was accomplished
during closecut of residual items from the previous fire protection
program inspection (see NRC Inspection Report No. 50-289/87-06).
Further, a 10 CFR 50, Appendix R review was conducted by NRC staff
as documented in NRC Inspection Report No. 50-289/86-23. Accordingly,
these areas were not revisited, except as noted below.
5.2 Protection of Equipment
Within the last three months, the licensee identified certain
apparent failures to meet the technical requirements of 10 CFR 50
Appendix R for which an NRC staff exemption was not granted. The 10
CFR 50 Appendix R,Section III.G.2 requires, in part, that the
equipment (cables, pumps, valves, etc.) necessary to achieve hot
.
22
shutdown conditions be protected and remain free of fire damage by
several options specified in III.G.2 a through f (except as provided
in III.G.3). The staf f's safety evaluation, dated March 19, 1987,
for the licensee' exemption request to these. requirements, specifically
exempted certain equipment (which was not adequately protected) with
specific compensatory measures to achieve the same level of safety. For
equipment that needed to be operated manually in less than thirty minutes,
a roving fire watch was to assure timely identification and response to a
fire in areas that had unprotected equipment.
In particular, one group of exempted components was to assure RCP
seal integrity (seal injection / cooling). Normal action for fires in
CB-FA-28 and 2F) includes tripping of the RCP. An additional
commitment for this function on fire in CB-FA-2B and 2F was the
upgrading of the fire emergency procedure to dispatch an operator to
the RSP to restore seal injection or trip the RCP's locally in the ,
turbine building. On April 24 and May 1, 1987, and in a letter
dated May 7, 1987, to NRC staff, the licensee identified that
unprotected cables (as defined by III.G.2) for RCP seal injec-
tion / cooling were also in CB-FA-1 and that area was not under a
roving patrol, nor did the fire emergency procedure for a fire in
CB-FA-1 specifically address the additional commitments on operator
action. The licensee pointed out that other emergency procedures
would require those actions for RCP seal integrity anyway. The
letter noted that the RSP provides an alternative capability for
restoration of RCP seal cooling independent of CB-FA-1, including
fire protection and detection capability and that the requirement of
III.G 3 is met. Therefore, no exemption was required.
However, the letter requested that fire area CB-FA-1 be included in
the NRC staff's updated safety evaluation to ensure compliance with
10 CFR 50 Appendix R. The NRC staff will review the licensee's
(final) Fire Hazards Analysis Report, Revision 9, to be submitted
October 31, 1987. The NRC staff will review this matter for techni-
cal adequacy.
On June 25, 1987, the licensee identified to the NRC staff that
certain equipment for safe shutdown was unprotected for which no
exemption was granted by NRC staff. The equipment was in area
FB-FZ-1 (281 foot elevation, Fuel Handling Building) and it was
cabling for a local ventilation fan AH-E-ISB, which services the
nuclear services pump area in the auxiliary building (AB-FZ-7). The
licensee identified that the problem was noted during re-review of a
need for modification to adequately protect equipment associated
with the RCP seal injection / cooling issue.
The NRR staff informed the licensee a letter was needed to describe I
the technical solution or provide an exemption request to 10 CFR 50
Appendix R.
!
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23
The licensee added the FH-FZ-1 area to the roving fire watch patrol.
The licensee will be sending letter by July 27, 1987, to address
this item. The inspector expressed concern that the technical
shortcomings noted above poorly reflects on the licensee Appendix R
review as a whole unless they are indeed isolated cases. It was
noteworthy that these items were being identified by the
licensee / vendor and are being reported to NRC staff. The licensee
acknowledged the above and stated that their letter of July 1987 may
address whether or not these problems are indeed isolated cases.
-
The above items are unresolved pending completion of licensee action
as noted above and subsequent NRC staff review for technical adequacy
and/or appropriate enforcement action (289/87-11-04).
5.3 Remote Shutdown Panel Source Range Indication
For the startup after the letdown cooler outage, the licensee
decided that it was safe to proceed with the source range channel -__
(NI-9) at the remote shutdown panel (RSP) inoperable. There are no
technical specifications for the system and proposed technical
specification indicated that while the RSP is inoperable or any
portion thereof, a written report would be made to NRC to identify
the problem along with taken/ planned action.
On July 8, 1987, the inspector determined that the licensee could
not immediately repair NI-9 because of a faulty detector. The plant
would have to be shutdown for such repairs.
Further discussions revealed that the control building roving fire
watch was instructed to pay attention to the cables for NI-1/2
(other source range channels indicated in the control room) cable on
tours. The inspector questioned if that was an equivalent fire
protection measure. Further, the 'icensee plans to submit a letter
outlining corrective actions by July 31, 1987. Tentatively, it
appears that, if a shutdown in excess of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> were to occur, the
licensee would plan to replace the ill-9 detector.
The operability of NI-9 is unresolved pending NRC staff review of
the above noted letter to the NRC staff (289/87-11-05).
5.4 Fire Protection Summary
Generally, the fire protection program at TMI-1 continues to be
properly implemented. Housekeeping is acceptable and control of
transient combustibles is generally not a problem. The inspector
reviewed several recently completed fire protection engineer weekly
walkdowns of the plant spaces. These walkdowns identified some
minor discrepancies but they were promptly corrected. The inspector
noted sufficient evidence of the proper implementation of this
program. This inspector had no other safety concerns on the fire
protection program.
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.
i
. 24
The problems being identified for Appendix R work show signs of weak
technical support. Further review by the licensee and NRC staff is
needed.
6. Licensee Actions on Previous Inspection Findings
6.1 (Closed) Unresolved Item (25-00-16): NRC Temporary Instruc
tion, " Seismic Interaction for Incore Nuclear Instrumentation"
The NRC staff's Temporary Instruction (TI) 2500/16 was issued to
provide inspection guidance concerning IE Information Notice 85-45,
" Potential Seismic Interaction Involving the Moveable Incore Flux
Mapping System at Westinghouse (W) Plants."
The configuration that exists at TMI-1 on Babcock and Wilcox (B&W)-
designed plants is not similar to the W-designed plants in that the
incore flux detectors are permanently installed in the core at B&W.
The inspector considered the issue of TI 2500/16 applicable to
TM1-1; namely, the adequacy of non-seismic equipment over
seismically-installed equipment. The seal table exists on the
operating floor of the reactor building, but no equipment or machin-
ery for detector movement is required. The flux detectors are
removed from the core during refueling evolutions by using an
overhead jib crane mounted on the wall of tLe "D-ring" adjacent to
the incore seal table. During plant operati3n, this jib crane is
not located over the seal table and is secured in position on the
D-ring by cables and turn buckles to prevent it from falling onto
the seal table during a seismic event.
General Maintenance Procedure (MP) 1401-18, Revision 2, " Equipment
Storage in Class I buildings," was reviewed by the inspector. This
procedure specifies the requirements and methods to secure this
crane to prevent its movement during normal plant operations. The
inspector also verified after the latest outage that the jib crane
was properly secured and stored.
The licensee was aware of the concerns in Information Notice 85-45
and had evaluated the situation as not being applicable to TMI-1.
The reason was that TMI-1 is not a W-designed plant.
The inspector concluded that, based on the type of arrangement used .
for the incore instrumentation at TMI-1, no concern of the type '
identified in IN 85-45 exists at TMI-1. Adequate actions have been
taken to prevent damage to the incore seal table so as to preclude
any damage during a seismic event at TMI-1. The inspector had no
other concerns and this temporary instruction is considered closed
for TMI-1. Additional work on seismic interaction throughout the
plant will occur related to Generic Letter 87-02.
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, 25
6.2- (Closed) Unresolved Item (289/85-24-01. Training Feedback
An Atomic Safety and Licensing Board (ASLB) Partial Initial Decision
'(PID), dated May 3, 1985, required the licensee-to develop a method
to provide supervisors with a means to.give feedback to training ,
programs by licensed operators directly evaluating the effect of
training on the actual job performance of trainees under their
supervision (performance based training evaluation). At the time of i
'NRC Inspection No. 50-289/85-24, a licensee-developed procedure to ;
accomplish this objective.had not been implemented for licensed
operators and the item was-left unresolved.
. Subsequent review of this item was reported in NRC Inspection Report
No.'50-289/87-09 during which the inspector identified one remaining
concern. The method by which the licensee was documenting the
supervisors feedback allowed for the use of this process'by the
operators themselves to voice concerns or suggest improvements in
~
training. However, separate mechanisms existed for operator / trainee
feedback,' which were intended to be distinct from-that for supervi-
sors. The supervisors own evaluation was not directly required.
'The inspector reviewed the licensee's memora'nda and the supervisor
feedback forms for the evaluations which covered the one year period
ending in March 1987. Licensee training staff. representatives met
one-on-one with each supervisor to' explain the objective of the
evaluation and to ensure the proper level of analysis and suggested
improvement were taking place. Based on this and the previous
review, the inspector. concluded that the licensee's procedure now
adequately addresses the original concern.
Furthermore, the inspector noted that this feedback input is only
one of several that the licensee uses for improving training. Other
inputs ~ include requalification. examination results, simulator
evaluations, TMI and industry operational events, operations depart-
ment inputs, NRC/INP0/ internal audits. These changes are comprehen-
sive, well documented, and exceed minimum regulatory requirements.
6.3 (Closed) Inspector Follow Item (289/86-03-15): Licensee
Review / Modify Maintenance Procedure for Limitorque Motor-Operated
Valves
Two maintenance procedures, Corrective Maintenance Procedure l
'
1420-LTQ-2, Revision 8, and Preventive Maintenance Procedure E-131,
Revision 12, for Limitorque motor-operated valves were identified as l
having various weaknesses concerning adjustments to the limit '
switches 'or in specifying valve operation. The inspector reviewed
current revisions to the subject procedures, Revision 10 to
1420-LTQ-2 and revision 13 to E-13 and he verified that the previous
concerns had been addressed.
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.
26
Procedure 1420-LTQ-2 now specifies that a more precise valve open
position (6 percent of total handwheel turn) be maintained when
setting the open limit switch. Previous guidance was that the valve
be open "a slight amount." This change was considered satisfactory
by the inspector to correct any doubt as to what valve position is
required to set the open limit switch.
The second concern was that the torque bypass switch could have been
set such that unseating forces would not be overcome before torque
switch trip at the previously specified 3-10 percent open position.
The procedure now specifies that 10 percent (+4 - 2) of valve stroke
time be attained for setting the opening of the torque bypass
switch. The inspector concluded that this was acceptable. Previous
guidance has determined that 8-14 percent of valve travel be allowed
prior to bypass switch actuation.
Procedure E-13 was modified to delete reference to " jogging" the
valve to verify proper motor rotation. The procedure now correctly
specifies how to operate the valve to check correct motor rotation.
The inspector concluded that the above-noted procedure enhancements
were adequate to address the previously-noted concerns and this item
is closed.
6.4 [0 pen)UnresolvedItem(289/85-25-05): Steam Generator Safety
Valve Performance
Additional information on this item was obtained during a post-trip
review (see paragraph 4.3.4).
6.5 (0 pen) Unresolved Item (289/87-02-01): NRC to Review Licensee
Investigation of Drug Abuse
During this inspection period, the licensee concluded another
investigation of drug abuse by its employees and/or contractor
personnel.
Since May 19, 1987, the licensee has frequently briefed NRC staff on
their investigation. On June 15, 1987, the licensee concluded their
review and issued a press release on their investigation. The
l
licensee confirmed positive drug test results have been received on
ten employees. Of the ten employees, one has resigned, one was
fired for failing to cooperate with the investigation, and eight
have been suspended without pay. One additional employee refused to
undergo testing and was discharged. There are no positive test
results (or test refusals) involving licensed operators or manage-
ment personnel.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - - __
.
27
The eight suspended employees were given the opportunity to regain
their jobs after thirty days if they successfulD completed a
rehabilitation program and subsequent evaluation by a GPU Nuclear
psychologist. A licensee representative reported that all eight
employees accepted the licensee's offer and terms which included
periodic and random testing for drug misuse.
The licensee indicated that, similar to a previous investigation, an
internal investigation report would be issued. This area continues
to be unresolved pending NRC staff specialist review of the
licensee's internal reports on these matters.
6.6 {0 pen)InspectorFollowItem(289/87-07-01): Individual
Documentation of Operator Performance during Simulator Evaluations
The licensee committed to document individual performance, as well
as team performance during simulator evaluations. This area will be
reviewed again by NRC staff after the licensee's next annual simala-
tor examinations in March 1988.
6.7 (0 pen) Inspector Follow Item (289/87-07-02): Senior Licensed
Operators Not Evaluated During Simulator and Oral Examinations at
the Senior License Level
The licensee has added a statement to a proposed revision to their
corporate requalification program description clearly specifying
that senior reactor operators (SR0's) will be evaluated in SRO
positions during simulator examinations. Two senior operators who
did not' receive this type of evaluation (apparently because they
normally stand reactor operator watch) during the licensee's March
1937 simulator examinations will be given additional simulator
evaluations by the licensee during July 1987. This item can be
closed out following notification by the licensee that the
requalification program description is approved as drafted and the
additional simulator examinations scheduled for July 1987 are
complete.
6.8 Past Inspection Findings Summary
Overall, the licensee was responsive to address previous inspection
issues / concerns.
7. Exit Interview
I
The inspectors discussed the inspection scope and findings with )
licensee management at a final exit interview conducted July 9, 4
1987. Senior licensee personnel attending the final exit meeting l
included the following:
C. Incorvati, Audits Supervisor, TMI-1
M. Ross, Director, Plant Operations, TMI-1
C. Smyth, Licensing Manager, TMI-1 ;
.______-_______-__
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28
The inspection results as discussed at the meeting are summarized in
the cover page of the inspection report. Licensee representatives
indicated that none of the subjects discussed contained proprietary
or safeguards information.
Unresolved Items are matters about which more information is re-
quired in order to ascertain whether they are acceptable, viola-
tions, or deviations. Unresolved items discussed during the exit
-meeting are addressed in paragraphs 2.2.3, 2.2.5, 3.3.3, 5.2, 5.3,
and Section 6.
Inspector Follow Items are significant open issues warranting
follow-up by the inspector at a later time to determine if it i's
acceptable, unresolved, a violation, or a deviation. An inspector
follow item discussed during the exit meeting is addressed in
paragraph 6.3 of this report.
l
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NRC INSPECTION REPORT
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NO. 50-289/87-11
ATTACHMENT'l
ACTIVITIES REVIEWE0
Plant Operations
--
Control room operations during regular and backshift hours, including
frequent observation of activities in process'and periodic reviews of
selected sections of the shift foreman's log and control room. operator's,
~1og and selected sections of'other control room daily logs
--
Areas outside the control room
--
Letdown' cooler shift due to high leak rate from "1B" heat exchanger
on June 3, 1987-
--
Unplanned reactor trip, Emergency Procedure 1210-1 on June 12,'1987
-
--
Operating Procedure (OP) 1102-11,- Revision 68, dated March 15, 1987,
" Plant Cooldown," on June 12-13, 1987
--
OP'-1102-2, Revision 80, dated May 15, 1987, " Plant Startup," includ-
ing the license heatup/startup prerequisite list and related activi-
ties on June 25-26,L1987 1
--
OP 1104-8, Revision 27, dated January 26,.1987, "ICCS System Operation,"
(TCN 1-87-138) on June 24, 1987
During this inspection period, the inspectors conducted direct inspections
during the following backshift hours:
'6/01/87 8:00 p.m. to 10:30 p.m.
6/02/87 6:00 a.m. to 7:00 a.m.
3:00 p.m. to 5:00 p.m.
6/06/87- 9:00 a.m. to 10:30 a.m.
6/12/87- 7:00 p.m. to 10:30 p.m
6/13/87 9:00 a.m. to 1:00 p.m.
6/24/87 5:00 p.m. to 8:00 p.m.
6/25/87 4:00 p.m. to 8:30 p.m.
6/27/87 8:00 a.m. to 10:00 a.m.
6/18/87 8:45 p.m. to 10:15 p.m.
7/09/87 5:00 a.m. to 7:00 a.m.
Maintenance
--
NR-P-1A Overhaul per Job Ticket (JT) CM-855
--
Corrective Maintenance Procedure 1410-P-14
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Surveillance
--
Surveillance Procedure (SP) 11.21, Revision 7, dated December 3,
193, " Core Flood Valve Operability Test," on June 13, 1987
--
SP 1303-4.16, Revision 29, dated June 23, 1987, " Emergency Power
' System for Diesel Generator B," on June 24, 1987
--
SP 1303-5.1, Revision 22, dated March 4, 1987, " Reactor Building
Cooling and Isolation System Logic Channel and Component Test," week
of July 6-9, 1987
--
SP 1303-5.2, Revision 24, dated March 10, 1987, " Load Sequence and
Component Test," week of July 6-9, 1987
--
SP 1300-3I, NR-P-1A Post-Maintenance Test (records review)
Reactor Coolant System (RCS) Leak Rate.
The inspector selectively reviewed RCS leak rate data for the past inspection
period. The inspector independently calculated certain RCS leak rate data
reviewed using licensee input data and a generic NRC " BASIC" computer program
"RCSLK9" as specified in NUREG 1107. Licensee (L) and NRC (N) data are
tabulated below.
TABLE
RCS LEAK RATE DATA
(All Values GpM)
DATE/ TIME (NUREG 1107) CORRECTED
DURATION Lg Ng Ng Ng L
U
6/1/87 2.1863 2.19 0.12 0.22 0.2236
3:41 p.m.
2 Hours
6/2/87 3.2235 3.23 -0.04 0.06 0.0401
10:34 a.m.
2 Hours
6/2/87 3.5089 3.50 0.13 0.23 0.2435
8:27 a.m.
2 Hours
i. -
L
l
l DATE/ TIME (NUREG 1107) CORRECTED
DURATION Lg Ng N
g Ng L
U
7/8/87 0.0924' O.09 0.12 -0.02 -0.0127
11:49 p.m.
2 Hours
G = Identified gross leakage U = Unidentified leakage
L = Licensee calculated N = NRC calculated
Columns 2 and 3; 5 and 6 correlate 1 0.2 gpm in accordance with NUREG
1107. (N is corrected by adding 0.1044 gpm to the NUREG 1101 N due to
u u
l total purge flow through the No. 3 seal from RCP's.
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