ML20150C257
| ML20150C257 | |
| Person / Time | |
|---|---|
| Site: | Fort Saint Vrain  |
| Issue date: | 06/21/1988 |
| From: | Farrell R, Heitner K, Michaud P, Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20150C219 | List: |
| References | |
| 50-267-88-12, NUDOCS 8807120380 | |
| Download: ML20150C257 (12) | |
See also: IR 05000267/1988012
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APPENDIX B
U. S. NUCLEAR REGULATORY COMt!!SSION
REGION IV
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. NRC Inspection Report: 50-267/88-12 License: DPR-34
Docket: 50-267
Licensee: Public Service Company of Colorado ~ (PSC)
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Facility Name: Fort St. Vrain Nuclear Generating StationE <
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Inspection At: Fort St. Vrain (FSV) Nuclear Generating Station, Platteville,
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Inspection Conducted: May 1-3 , 1988 , -
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Inspectors: - -
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-R. E. Farrell Senior Resident Inspector (SRI) Date
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P. W. McliTu'd, ResTden nTpector (RI) Tate'
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K. L. Heitner, NRR Project Manager
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Approved: 7' [.
T. F. Westerman, Chief
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Reactor Projects Section B
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- 8807120380 000706
PDR ADOCK0500g7
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Inspection Summary
Inspection Conducted May 1-31, 1988 (Report 50-267/88-12)
Areas Inspected: Routine, unannounced inspection of operational safety
verification, licensee event report review, monthly maintenance observation,
monthly surveillance observation, radiological protection, and monthly security
observation.
Results: Within the six areas-inspected, no violations were identified.
One deviation was identified in paragraph 3.
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DETAILS-
1. Persons Contacted
D. Alps, Supervisor, Security
- M. Block, Systems Engineering Manager
- F. Borst, Nuclear Training Manager
- L. Srey, Manager, Nuclear Licensing and Resources
- M. Cappello, Central Planning and Scheduling Manager
- R. Craun, Nuclear Engineering Manager
- D. Evans, Superintendent, Operations
a' *M. Ferris, QA Operations Manager i
- C. Fuller, Manager, Nuclear Production- .
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- J. Gramling, Supervisor, Nuclear Licensing Operations ,
- M. Holmes, Nuclear Licensing Manager
- F. Novachek, Nuclear Support Manager' .
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- R. Sargent, Assistant to Vice President', Nuclear Operations
- L. Scott, QA Services Manager
- N. Snyder, Maintenance Department Manager
- P. Tomlinson, Manager, QA
R. Walker, Chairman of the Board and CEO
- D. Warembourg, Manager, Nuclear Engineering
- R. Williams Jr. , Vice President, Nuclear Operations
W. Woodard, Health Physicist
The NRC inspectors also contacted other licensee and contractor personnel
during the inspection.
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- Denotes those attending the exit interview conducted June 9,1988.
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2. Plant Status
The reactor was operating at 80 percent power level at the close of the
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inspection period. The reactor was critical 31 percent of the inspection
period with turbine generator capacity factor of 13.8 percent for the
inspection period. The reactor scrammed-on May 6,1988, following a
helium circulator trip caused by a control systems malfunction. The
reactor was again taken critical on May 18. The turbine generator was
returned to service May 26. The reactor was run below turbine generator
service levels from May 18-26, 1988, for reactor coolant cleanup.
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During the inspection period the licensee implemented a.reorganizution of
its nuclear operations. This ha, been a much talked about reorganization, !
which has been in the planning stage for almost 2 years. The NRC
inspectors will closely monitor licensee's activities as the reorganization
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takes effect.
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3. . Operational Safety Verification (71707)
The NRC inspectors reviewed' licensee activities to ascertain that the
facility is being operated safely and in conformance with regulatory
requirements and that the licensee's management control system is
effectively discharging its responsibilities for continued safe operation.
The NRC inspectors toured the control room on a daily basis during' normal
working hours and at least twice weekly during backshift hours. -The
reactor operator and shif t supervisor logs and Technical Specification
compliance logs were reviewed daily. The'NRC inspectors observed proper
control room staffing at all times and verified operators were attentive
and adhered to approved procedures. Control room instrumentation was -
observed by the NRC inspectors and the operability of the plant protective
system and nuclear instrumentation system were verified by the NRC
inspectors on each control room tour. Operator awareness.and
understanding of abnormal or alarm conditions was verified. The NRC
inspectors reviewed the operations order book, operations deviation
report (0DR) log, clearance log, and temporary configuration report-(TCR)
log to note any out-of-scrvice safety-related systems and to verify
compliance with Technical Specification requirements.
The licensee's management representatives were observed in the control
room on a daily basis prior to the beginning of the day shift.
The NRC inspectors verified the operability of a safety-related system on
j a weekly basis. The reserve shutdown system, helium purification system,
prestressed concrete reactor vessel (PCRV) penetration purge flow, and
control rod drive motors and purge flows were verified operable by the NRC
inspectors during this report period.- During plant tours, particular
attention was paid to components of these systems to verify valve
positions, p wer supplies, and instrumentation were correct for current
plant conditions.
Shift turnovers were observed at least weekly.by the NRC inspectors. The-
information flow appeared to'be good, with the shift supervisors routinely l
soliciting comments or concerns from reactor operators, equipment )
operators, and auxiliary tenders. l
The NRC inspectors responded to the control room following a reactor scram
on May 6, 1988. The scram occurred after "B" helium circulator tripped
due to an upset in the Loop 1 bearing water surge tank. Approximately
- 2 minutes later a reactor scram on high hot reheat steam temperature
occurred. This was due to a failure of the cold reheat steam
attemperation flow to automatically increase following the circulator
trip. .Following the trip it was discovered that the hot reheat
, temperature signal supplied to the overall plant control. system had
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drifted such t N t it was reading 35 F below actual hot reheat steam
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temperature. The plant protective system, which was verified to have been
reading actual hot reheat steam temperature, thus saw the actual hot
reheat steam temperature reach the scram setpoint before the control
system detected anything abnormal.
Because of recent problems with radioactive releases via the core support
floor vent following a plant trip, the reactor _ operators were attempting
to reduce primary coolant pressure as fast as reasonably possible
following the trip. The rate at which the primary coolant was being
vented exceeded the capacity of the low temperature absorber in the helium
purification system. This caused the low temperature absorber.to heat up
and off gas into the coolant which was being vented into the helium
storage bottles. The off gassing of radioactive noble gases resulted in
radiation 1. ab a high as 125 mr/hr in the helium storage bottle area,
which was quickly posted as a high radiation area. The NRC inspectors
verified the dose rate at the posted boundaries was within the
requirements of 10 CFR 20.202. The situation was quickly recognized and
the rate of primary coolant depressurization was reduced. It was
subsequently determined that the corrective actions taken to address the
problem with the core support floor vent were successful in precluding the
need to rapidly depressurize the PCRV.
During the PCRV depressurization, the operating purified helium compressor
tripped. This resulted in a loss of buffer helium wakeup which, in turn,
resulted in a small amount of primary coolant flowing down the shaft of
"C" and "D" helium circulators. This primary coolant then mixed with
bearing water and ended up in the reactor building. It was subsequently
released to the atmosphere via the plant vent stack. The reactor building
atmosphere was measured at 3.6 E-8 microcuries per CC, and the accumulated
dose at the site boundary was calculated to be 1.94 E-7 Rems.
The NRC inspectors were in the control room immediately following the
reactor scram and remained there until the plant was stabilized. The
licensee's operations personnel were observed to be in control of the
plant at all times and responded to the event in a professiunal manner.
The licensee in a power ascension on May 26, 1988, experienced difficulty
in stroking valves HV-2292 and HV-2293. These valves are hydraulically
operated valves which direct main steam flow from the startup bype s
system to the main steam bypass system in preparation for startint iie i
turbine generator. These two valves must stroke closed during powa l
ascension after the main steam temperature reaches 760 F. The hydraulic
actuator on each of these valves is equipped with thermal relief valves to
protect the actuator against hydraulic pressure surges. It was a thermal
relief valve on HV-2292 failing to reset which initially led to the fire
experienced October 2, 1987. l
The problem experienced during this inspection period with HV-2292 and l
HV-2293 was with the thermal relief valves associated with the hydraulic !
actuators. A relief valve on HV-2292 was leaking slowly and was i
subsequently replaced. This is normal after very few strokes of the
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relief valve. The relief valve on HV-2293' failed to reseat af ter HV-2293
was stroked closed. The oil flow relieving through the thermal relief ,
valve was stopped by reopening HV-2293.. The thermal relief valve was
replaced, and HV-2293 was again closed. Again the themal relief valve
lifted, failed to reseat, and re.lieved oil to the oil recovery system.
Again the oil flow was stoped by opening HV-2293. The licensee noted
that the oil flow through tie thermal relief salve on the actuator of
HV-2293 was greater than expacted. There is a flow orifice 27 mils in
diameter installed upstream of these thermal relief valves to restrict
this oii flow. Additionally, restricting this-oil. flow serves to protect
the relief valves and prolong service life of the relief valves. In-
October 1987, it was' discovered that the orifice upstream of the thermal
rolief valve on HV-2292, which led to the fire, was not installed and
consequently the oil flow experienced was greater than could be handled by
, the oil recovery system.
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j While NRC inspectors watched, the thermal relief valve and associated
piping was disassembled on HV-2293. The flow orifice upstream of the
relief valve was missing. The licensee recovered the documentation of the
disassembly, inspection, and reassembly of HV-2293 following the
October 1987 fire and verified that mechanics had installed the flow
orifice and that quality control inspectors had witnessed the ;
installation. Additionally, the parties involved who had actually i
performed the work and inspection in 1987 were interviewed by the licensee ,
and insisted that they had indeed performed this work as documented. The
i licensee stated to the NRC inspectors that the men involved were
l considered to be particularly reliable. The mechanics probed the
connecting piping of the hydraulic actuator and did find the flow orifice.
This flow orifice is a screw which screws into a fitting and has a 27 mil
diameter hole drilled in it. Apparently this screw had vibrated out of
its fitting and fallen into a portion of the actuator piping where it
could not perform its function.
The licensee reinstalled the orifica and reassembled the actuator on
1 HV-2293. HV-2292 and HV-2293 were successfully stroked closed and power
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ascension continued. The licensee is preparing to disassemble and inspect i
- all hydraulic actuators with this type of orifice and will take corrective
steps to assure that the orifices are installed in a manner which
precludes vibrating out of position. The NRC inspectors will follow this
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a: tion and this is considered an open item (267/8812-01). .;
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By letter dated July 10, 1985, the licensee committed to follow certain l
! Interim Technical Specifications concerning reactivity control at FSV.
Interim LCO 3.1.1.C states for a control rod drive (CRD) to be considered
operable, there must be helium purge flow to each CRD penetration when
reactor pressure is above 100 psia. Interim SR 4.1.1.A.2 requires that l
purified helium flow to each CRD be verified by verifying flow at each '
subheader. The purpose of these requirements is to limit the upward flow
of contaminated helium coolant to the CRD mechanism in the CRD
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On May 18, 1988, at about 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br /> and on May 19, 1988, at about-
0815 hours0.00943 days <br />0.226 hours <br />0.00135 weeks <br />3.101075e-4 months <br />, the inspcctor observed helium flow at the subheaders
(FI-11268-3, 4, and 7) was reading zero or below iero. At the same time,
flow indication for some individual CRD penetrations read zero or below
zero. (These flow indicat$ons were read both locally in the reactor
building and remotely in the control room.).
At this time the reactor pressure was above 100 psig (172 psig on May 19
at 0815 hours0.00943 days <br />0.226 hours <br />0.00135 weeks <br />3.101075e-4 months <br />). _ The inspector observed that the licensee's-
instrumentation did not indicate compliance with LC0 3.1.1.C. .The
licensee stated that the instrumentation might_not read correctly because
of reduced reactor-coolant density (approximately 39 percent of full
value).
The NRC inspectors requested the licensee provide the surveillance
procedure to satisfy the requirements of Interim SR 4.1.1.A.2 and
compliance with Interim LC0 3.1.1.C. The licensee provided pages from the
reactor building equipment operator round sheet. This sheet required only
that the subheader flow be greater than zero in order to satisfy the
LC0 3.1.1.C.
The NRC inspector noted that this criteria for surveillance of subheader
purge flow does not reflect the reactor's design criteria. Specifically,
the licensee's Reference Design Manual, 50-11-6, notes the helium purge
flow is to be 5.5 lbs/hr per penetration (at full helium density). The
greater than zero criteria would also allow instrumentation error to
falsely indicate that there is adequate flow.
The NRC inspectors concluded that the licensee's current surveillance
procedure is inadequate.
In subsequent discussions with the inspector, the licensee stated that by
reducing all indications to a common basis, approximately 2.5 to
2.8 ACFM of flow was indicated at 170 psia for the total system. By
contrast, the control system was set to deliver 7.4 ACFM. Thus, the
system was not operating correctly when observed by the NRC inspector. The
licensee was informed of the NRC inspector's' observation of the apparent
malfunction of the control 'systet.s for helium purge.
It is not apparent that the licensee has implemented measures to assure-
compliance with his July 10, 1985 commitment to follow Interim Technical
Specification LC0 3.1.1.C. ThisIsanapparentdeviation(267/8812-02).
On a tour of the control room, the NRC inspectors found a television set
and a connected video tape machine in the kitchen behind the: atrol
boards within 'he control room vital area. The equipment wa3 not in use
at the time. but the NRC inspectors immediatelv interviewed the licensee's
operations suW rin,endent as to why this equipment was in the control
room. The operati(ns superintendent explained that people on shift could
not attend regular 1y scheduled safety meetings. Consequently, the
licensee was videc taping the safety meetings and allowing the operating
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crew to watch the video : o of the meeting >when.they could. This
activity was taking place at kitchan.behind the control boards ir, the-
control room vital area. li MC 'nspcctors inquired as to why-this
activity had to take place in - ontrol room since the control roon,
operators could not perform ti technical specification required
licented activities in front une control boards and also watch tne
video tape simultaneously. The operations superintendent agreed and the
- equipment was removed from .,he control roo'm vital area to an office area
nearby where on shift personnel, who are not renuired to be. in tha
control room at their stations, can watch the video tapes of-the safety
meetings during their shifts. The licensee advised the NRC inspectors
that persons required by Technical Specifications.to be at their stations
within the control room will, in the future, watch the video tape of the
safety meetings after being relieved from their pest.
There-has been r.o time when the NRC inspectors have observed less than
minimum Technical Spec:rication required manning ~in front of the control
panels in the control room. At no time ilave the NRC inspectors observed
on-duty licensed reactor operators watching television or participating in
other activities-that would divert their attention from their duties.
During tours of the facility, the NRC inspectors noted that the average
age of deficiency report tags (DRTs) appears to be growing. The DRT
system developed by the licensee identifies equipment already logged as
requiring maintenance and also allows observers to trace the maini,enance
requests pending to repair the equipment. However, the NRC inspectors
noted that the requests once gene.'ated do not appear to be closed in a
timely manner. Observed examples are as follows.
DRT 004061 on valve V-6223 is dated Septemt,er 3,1986.
DRT 004062 on valve V-6222 is dated September 3,1986.
ORT 010055 on valve V-91141 is dated January 26, 1988. This is a
hydraulic system valve and the LRFdocuments a missing hand wheel.
The h6nd wheel was still: missing on May 6, 1988. The NRC inspector
noted that a: missing hand wheel on a: hydraulic system valve aggravated
the fire experienced October 2, 1987. The valve part is on back
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DRT 004450 on M-82, a broken box protecting instrument valves, is ;
dated January 25, 1987. '
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DRT 005054 on valve HV-2189-8 dated August 5, 1987.
The licensee has been informed of the NRC inspector's observation of the l
excessive time required to close DRTs. The licensee is cornidering actions
to address this issue. This item is considered an open itoa (267/8812-03).
On a tour of the 480 V switchgear room, the NRC inspectors noted that some
electrical cable conduits were quite warm to.the touch. The licensee's
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shift supervisor, maintenance manager, and electrical maintenance
supervisor were interviewed regarding these conduits. This condition had
previously been identified by' licensee _ personnel. The licensee'.s .
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engineering organization has.determinedithat-the cable in these. conduits
is qualified'to.a' higher temperature than canibe tolerated by' human touch.
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Consequently, the cables were within their qualified parameters. The
licensee also advised that' the particular conduits carried power. cables :to
a bearing water pump motor. This'is.a large 480 V motor and the conduit
temperature'is expected to be warm when the motor is running.
No violations or deviations ware identified in the review of this program
area.
4. Review of Licensee Event Reports (LERs) (90712)
The NRC inspectors reviewed the LERs listed below during this inspection
period. This review verified that each.LER was submitted within-the
required time, the description of the occurrence is accurate, a root cause
was established where possible, and the corrective actions taken or
proposed are appropriate. The five LERs reviewed were found to be
acceptable in these areas. The LERs are:
LER 88-07, Surveillance Procedure not_ Performed Mithin Technical
Specification Interval Due to Error in Computer Scheduling Program
LER 88-06, Expansion Joint Failure Causing Losa of Circulating Water
Resulting in a Manual Scram
LER 88-05, Neutron Flux Rate of Change High Scram (while shut down)
LER 88-04, Manual Scram Due to Power' Grid Fluctuecions
LER 87-23, Revision 1, HV-2292 Oil Leak Caused Fire and Manual Scram
Mo violations or deviations were identified in the review of this program
area. ;
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5. Monthly Maintenance Observation (62703)
The NRC inspectors monitored the licensee's efforts to troubleshoot tL
prestressed concrete reactor vessel (PCRV) penetration interspace purge
flow indication, FI-11263, located in the control room. This instrument
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is used to verify compliance with Technical Specification 4.2.7, which
requires the interspace between primary and secondary PCRV penetration i
seals to be pressurized. A purge flow of purified helium maintains this !
pressurization.
ORT 9282 identified a problem with flow indication FI-11263 cycling
between 0 and 3 ACFM. The flow element was removed and cleaned, which '
returr.ed the instrument to its normal indication of cycling-between l'and
2 ACFM. The licensee's system engineer then performed a test of an
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electrical-dampening circuit which took a 2-minute average of.the
normally cycling signal and gave a time averaged,-steady indication. -.This
. test was performed under. test procedure:T-362, which the NRC inspectors
reviewed and'found acceptable. The purpose of this test was.to prove;the
feasibility of modifying the instrument .to provide a mcre steady, but - -
still meaningful, indication. . Based on the. licensee's evaluation of the
test data, a permanent change notice is being developed-to modify the
circuitry for this instrument. The NRC inspectors will monitor the i
licensee's progress in this area.
The NRC resident inspector followed the licensee's actions to check the
operation of the Loop 1 bearing water s Jrge tank level control system
following the plant trip on May 6, 1988. .A level excursion in the Loop 1
bearing water surge tank was the cause of the loss.of "B" helium
circulator, which was followed by a reactor scram. Troubleshooting
efforts discovered the Hi-Hi level dump valve on the surge tank was
opening at an approximately 18 inch leQ. The surge tank-. level is.
normally controlled at 17 inches with the Hi Hi level dump valve set at
23 inches. The licensee was not able to establish a reason for the Hi-Hi
level dump valve setpoint being as found. The fact that it was operating i
at that point does explain how a level excursion could have occurred under
normai operations. The NRC inspectors verified both the Loop 1 and Loop 2
bearing water surge tank level controls were calibrated prior to returning
to power operation.
During power ascension, the fluid in the main steam lines at FSV goes from
water to wet steam to superheated steam depending upon the'. power level at ,
the time. Consequently, the safety relief valves in the main steam lines
are designed to handle water, wet steam, or superh_eated steam. ' The #
particular design of these safety relief valves causes them to perform
best and co be most leak tight when exposed to superheated steam. The
manufacturer does recommend gagging leaking valves when the working i
fluid is water or we' Jte6m. There are three safetyfrelief valves on each
main steam line and t w wer operated relief valve on each main steam line.
Each of the safety relief valves'(SRV) will pass approximately 34 percent. <
of the full flow of its associated main steam line,
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On May 25, 1988, the NRC inspectors noted that SRV V-2214 was gagged in I
main steam Loop 1 and SRV V-2245 was gagged in main steam Loop 2. The NRC l
inspectors interviewed the maintenance supervisor responsible-for gagging 1
the valves and reviewed station service requests (SSRs) 88503122, which
authorized gagging V-2245, and SSR 88503082, which authorized gagging.
V-2214. The NRC inspectors noted that in both cases quality control had
inspected the installation of the gags on the safety relief valves and that !
SSRs for gagging safety relief valves stay open until the gag is again- '
removed. The controlled work instructions (part of the SSR) stated iri a
note to Step 8, "Gag must be removed before going above 30 percent." The.
NRC inspectors verified by personnel interview, documentation review, and
visual inspection that the-gags were removed from the safety relief valves- !'
when the facility went above 30 percent power.
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The NRC inspectors also reviewed the documentation and witnessed portions
of the work of SSR 88500302 "Perform Quarterly Inspection." - This was.the
flushing and quarterly maintenance on the "B"-Instrument Air Compressor.
The preventative maintenance was being performed according to.
Procedure MP-7055 (Q), Issue 1,'"Quarterly Inspection and Preventative
Maintenance, Guardner-Denver Instrument: Air Compressor." The SSR~also
incorpt.ated by Reference Procedure ME-iO51, . Issue 3, "Guardner-Denver Air
Compressor, Coolant System, Chemical Cleaning Procedure Using Rydlyme." 1
No violations or deviations were identified in the review of this program
area.
6. Monthly Surveillance Observction (61726}
Ouring the course of the inspection period,.the NRC inspectors monitored
the Technical Specification 1 surveillance logs'to assure that Technical
Speciff ation required surveillances were current. Additionally, they
observed performance of parts of the following surveillances:
Emergency Diesel Generator Weekly Load Test
Radiation Monitor Operability. Test-
Gaseous Radwaste System Surveillance
Vital Area Door Alarm Test
Primary Coolant Chemistry Analysis
Alternate Cooling Method Diesel Generator Weekly Test
The NRC inspectors reviewed-the results of the 10-inch scram tests and
back-EMF tests on the control rod drives performed during the course of
the month.
The NRC inspectors also met with the licensee's technical staff 'to' review-
licensee use of a new computer code for doing-fuel analyses'and
accountability required by 10 CFR Part 74.13. The NRC inspectors
conferred with the NRR Project Manager. Based on the interviews with the
licensee and discussions'with the NXR Project Manager, the NRC inspectors
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have no feether questions at this time' regarding use of this computer
code.
No violations or deviations were identified in the review of this program
area.
7. Raalological Protection (71709)
The NRC inst. ' tors verified that required area surveys of exposure rates
are made and posted at entrances to radiation areas and in other
appropriate areas. The NRC inspectors observed health physics
professi_onals on duty on all shifts, including the backshift. The NRC l
inspectors observed the' health physics technicians checking area radiation j
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monitors, air samplers, and doing area surveys for> radioactive-
contamination. The NRC-inspectors observed the health physics technicians
checking prin,ary coolant chemistry for total-oxidants.
No violations or deviations _were identified in the .eview'of this. program
area.
8. Monthly Security Observation (71881)
The NRC inspectors verified that there was a lead security officer (I M
on duty authorized by the facility-security plan to direct security.
activities onsite for each shift. The LSO did not have duties that would
interfere with the direction of security activities.
The NRC inspectors verified, randomly and.on the backshift, that the
minimum number of armed guards required by the facility's security plan .;
were present. A 100 percent hands-on search was being utilized threughout
the inspection period as the licensee was unable to declare the new metal
detector. operable.
The protected area barrier was surveyed by the NRC inspectors. -The
barrier was properly maintained and was not compromised by erosion,
openings in the fence fabric, or walls, or proximity of vehicles, crates
or other objects that could be used to scale the barrier. The NRC
inspectort observed the vital area barriers were well meintained and riot
compromised by obvious breaches or. weaknesses. The NRC inspectors- '
observed tnet persons granted access to the site are badged indicating
whether they had unescorted or escorted access authorization.
The NRC inspectors obserled armed response force deployment when badged
unescorted individuals attempted to enter. areas for which they did not
have access. No deliberate attempts to-violate access levels,were
observed. Rather, newly badged individuals have recently shown a
propensity to confuse the central alarm station door with the reactor
building entrance. The NRC inspectors observed that the security force ,
responded according to .the security plan. ;
No violations or deviations were identified in-the review of this program
aiea.
9. Exit Interview (30703)
An exit meeting was conducted on June 9, 1988, attended by those
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identified in paragraph 1. At this time the NRC inspectors reviewed the
scope and findings of the' inspection.
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') . !
,
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-