ML20204K117
| ML20204K117 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 10/12/1988 |
| From: | Cooper R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20204K112 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737 50-341-88-21, NUDOCS 8810250349 | |
| Download: ML20204K117 (18) | |
See also: IR 05000341/1988021
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
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Report No. 50-341/88021(DRP)
Docket No. 50-341
Licerise No. NPF-43
Licensee:
Detroit Edison Company
2000 Second Avenue
Detroit, MI 48226
Facility Name:
Fermi 2
Inspection At:
Fermi Site, Newport, Michigan
Inspection Conducted:
July 16 through August 31, 1988
Inspectors:
W. Rogers
T. Silko
S. Stasek
K. Ridgeway
/o/[t/tf
Approved By:
R. Cooper
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ReactorProjectsSection3B
Date
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Inspection Summary
Inspection on July 16 to August 31, 1988 (Report No. 50-341/88021(DRP))
Areas Inspected:
Action on previous inspection findings; operational safety;
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maintenance; surveillance; followup of events; LER followup; startup test
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observation; personnel qualifications; regional requests; and review of
allegations.
Results:
Two violations were identified (Paragraph 3).
One unresolved
item Ta's identified (Paragraph 6) and four open items were identified
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(Paragraphs 3, 4, 7 and 10).
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8910250349 881014
ADOCK0500gg41
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DETAILS
1.
Persons Contacted
a.
. Detroit Edison Company
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- P. Anthony, Licensing
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L. Bregni, Senior Licensing Engincor
R. Bryer, Safety
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- S. Catola, Vice President, Nuclear Engineering and Services
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T. Dong, Safety
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C. Gelletly, Nuclear Engineering General Supervisor
- D. Gipson, Plant Manager
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- L. Goodman, Licensilig
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D. Grimes, Fluids Systems Engineer
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G. Hunt, MTE Support
R. Lenart, Nuclear Engineering General Director
P. McComish, Safety
R. Matthews, I&C General Superintendent
T. Meesseman, Training
- W. Orser, Vice President, Nuclear Operations
- G. Preston, Operations Engineer
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- T. Riley, Supervisor Compliance
J. Sabo, Plant Engineer
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H. Sierra, Technical Staff Engineer
- R. Stafford, Director NQA and PS
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W. Terrasi, General Supervisor Chemistry
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- W. Tucker, Operations Superintendent
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J. Wald, Production Quality Assurance Supervisor
E. Wilds, Lead Engineer Fluids
L. Wooden, Nuclear Engineering Staff
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b.
U.S. Nuclear Regulatory Commission
K. Ridgeway, Senior Resident Inspector, Lacrosse
- W. Rogers, Senior Resident Inspector
T. Silko, Inspector
- S. Stasek, Resident Inspector
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- Denotes those attending the exit meeting on September 20, 1988.
The inspectors also interviewed others of the licensee's staff during
this inspection.
2.
Followup on Inspector Identified Items (92701)
a.
(Closed) Unresolved Item 341/88003-07:
Adequacy of locked valve
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guidelines.
In a previous inspection, the inspector questioned
why Valves B21-F077A/B, 821-F104A/B/C/D, P44-F400A/B and numerous
other valves were not identified in the licensee's locked valve
program.
The inspector requested that the locked valve guidelines
be provided.
The guidelines provided were from Procedure 21.000.14,
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"Locked Valve Guidelines." This procedure stated that val'es
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without position indication in the control room in ESF systems
where misalignment could defeat the safety function of the system
or decrease its capacity or state of readiness should be in the
program.
The valves identified by the inspector met this criteria
but were not in the program.
This procedure was used to implement
a NUREG-0737 item as disCJssed in the FSAR Section H.II.K.1.5.3.
Therefore, this is considered a violation (341/88021-01) of
Technical Specification 6.8.1.b for failure to implement Fermi 2
cotlitments made in response to NUREG-0737 requirements.
Presently,
the licensee is reviewing ESF systems versus the locked valve
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criteria,
b.
(Closed) Unresolved Item 341/87009-02:
Testing of main steam
isolation valve leakage control system (MSIVLCS) deactivate
circuits.
The inspector requested NRR review of this circuit
as to is applicability under Technical Specification surveillance
testing.
In a memorandum dated June 12, 1988, NRR responded that
the circuit is required to be tested under Technical Specification
requirements.
The inspector informed the licensee of this position
which the licensee acknowledged and showed the inspector a revised
surveillance procedure reflecting appropriate circuit testing.
The
procedure had been revised and performed prior to issuance of the
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NRR letter.
Since the matter was corrected and did not appear to
have generic significance, this matter is considered resolved.
c.
(Closed) Unresolved Item 341/87026-05:
UFSAR accuracy.
The
licensee reviewed the Safety Evaluation. Logs for 1985, 1986 and 1987
and determined that 87 entries needed further review to determine
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whether they were incorporated into the UFSAR.
Four entries were
determined to need incorporation.
The inspector determined that
these actions were sufficient to resolve the inspector's concerns.
d.
(Closed) Open Item 341/80003-03:
Feedwater control system problems.
The licensee discovered and repaired a large oil leak and performed
troubleshooting / tuning of the control system circuitry.
Following
these actions the licensee was able to successfully pass feedwater
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control testing.
This matter is considered closed.
e.
(Closed) Unresolved Item 341/88003-04:
Independent verification
deficiencies.
Violations 88012-02 and 10 superseded this matter
by eleveting independent verification concerns to the violation
category.
This matter is considered closed based on issuance of
these violations.
f.
(0 pen) Open Item 341/87020-01:
EX0-Sensor Action Plan.
To resolve
reliability concerns reported under a Part 21 report, the licensee
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implemented an action plan to assure operability of the drywell
H2/02 sensors in the Post Accident Monitoring System.
This plan
consisted of:
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(1) Performing a function test of the sensors every 31 days.
(2) Changing out the sensore every six months.
(3) Reducing sensing line heat trace temperature ?.0+F to reduce
loss of electrolytes.
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(4) Pursuing with the vendor a new membrane made of a different
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material.
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Monthly functional tests conducted during 1988 have shown no problems
with the sensors; however, several procedural problems had to be
resolved during this periou.
Deviation Event Report (DER) 88-1237,
was issued on June 29, 1988, when the six month changeout of the H2
sensor could not be made since it was on a QC hold because the vendor
source surveillance check had not been completed prior to delivery.
It was returned to the vendor for the source check, but it was not
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available at the site in time to meet the scheduled six month
replacement.
A change in the vendor's ownership in late 1987 has
complicated the quality control, and a. vendor inspection by.DEC0
when the sensor was returned showed several deficiencies in the
new vendors quality program.
Corrective actions'are underway.
The reduction in sensing'line neat tracing temperature has
been initiated to decrease the loss of sensor electrolyte.
The electrolyte loss for the first sensor exchange in July
was not yet available.
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Discussions have been held with the' vendor on possible new membrane
material, but this will be a long term item.
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g.
(Closed) Unresolved Item 341/86039-05:
Emergency core cooling flow
control setpoints.
In Inspection Report No. 86039, the inspector
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documented that the licensee considered the ECCS flowrates in the
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Technical Specifications as nominal values instead of absolute
values.
As such the licensee did not account for instrument
inaccuracy in assuring the appropriate flowrate was achieved.
to the reactor vessel for HPCI & RCIC.
The inspector requested
confirmation from NRR that the Technical Specification values
were absolute instead of nominal.
In a memorandum dated June 22,
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1988, NRR confirmation was received which stated in part "All numbers
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in the TSs should be considered absolute unless otherwise noted."
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Therefore, the licensee did not meet Technical Specification
Surveillance Requirement 4.5.1.a.3 for having the HPCI flow
controller in the correct position or 4.7.4.a.3 for the RCIC flow
controller.
The difference was 40 gpm for RCIC and 200 gpm for
HPCI.
This is considered a violation (341/88021-02) of Technical Specifications 4.5.1.a.3 and 4.7.4.a.3.
The generic implication of
using nominal in lieu of absolute values for establishing controller
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setpoints is also of concern.
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No other violations or deviations were identified in this area.
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3.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable
als and conducted discussions with control room operators during the
period from July 16 through August 31, 1988.
The inspectors verified
the operability of selected emergency systems, reviewed tagou'; records
and verified proper return to service of affected components.
Tours of
the reactor building and turbine building were conuucted to observe plant
equipment conditions, including potential fire hazards, fluid leaks, and
excessive vibrations and to verify that maintenance requests had been
initiated for equipment in need of maintenance.
The inspectors, by observation and direct interview, verified that the
physical security plan was being implemented in accordance with the
station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and
verified implementation of radiation protection controls.
During the
inspection, the inspectors walked down the accessible portions of the
standby gas treatment and standby liquid control systems to verify
operability by comparing system lineup with plant drawings, as-built
configuration or present valve lineup lists; observing equipment
conditions that could degrade performance; and verified that
instrumentation was properly valved, functioning, and calibrated.
The inspectors also witnessed portions of the radioactive waste system
controls associated with radwaste shipments and barreling.
These reviews and observations were conducted to verify that facility
operations were in conformance with the requirements established under
Technical Specifications, 10 CFR, and administrative procedures.
During these reviews:
a.
A discussion was held between the inspector and the licensee
regarding HPCI and RCIC oil sampling.
At the time of the discussion,
if an oil sample showed a high particle count, instructions would be
provided to operations for a method of cleaning the oil, but guidance
was not offered as to whether the system should be declared
inoperative.
Procedure 71.000.15, Attachment 2, "Oil Change Data
Sheet," was revised such that if the results of the oil sample show
a particle count greater than that specified in the "out of
specification" range, the system is to oe declared inoperative per
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Technical Specifications by the NSS, until such time that oil purity
has been restored to at least the "requiring purification" range.
The inspector has no further questions in this area,
b.
The inspector discussed with the licensee the placing of the HPCI
and RCIC pumps physically inoperative when the external purifier
(non-seismic) is added to the system.
The licensee is considering
declaring the system administratively inoperative rather than
physically removing the system from service and declaring the
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system inoperative when the external purifier is in use.
The
inspector concurs that administrative 1y declaring the system out
of sarvice, rather than physically removing the system from service
is a more prudent action and will increase the availability of the
system to perform its intended safety functions.
The. inspector
has no further questions in this arec.
c.
The inspector noted during walkdowns in the con',ro' room, that area
lighting levels varied significantly shift to
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When questioned
about the variance, operatcrs stated that nn
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provided and, therefore aach shift adjustas
.evel of lighting
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to that which seemed mos,t appropriate and c
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Some shifts
preferred subdued lighting levels to allow toe easier identification
of indict. ting light status on the panels while others preferred more
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light to better read equipment tags and indicators / recorders.
Also,
the operators indicated that due to the design and/or placement of
the temperature controller (s) in the CCHVAC system, area temperature
levels become uncomfortably low at times and that by adjusting
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lighting levels, an alternate method of temperature control could be
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achieved.
The inspector then questioned licensee management whether.
this situation was in accordance with the guidance in NUREG-0700 or
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with the licensee's Detailed Control Room Design Review (DCRDR)
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conducted previously.
In response, an evaluation of control room
lighting was initiated, illumination limits were established and
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operators were instructed on maintaining lighting within the
appropriate limits.
The evaluation was conducted by engineering
and new limits communicated to the operators via a plant night
order.
This will remain an open item pending inspector review
of the newly specified limits and of the results of the licensee's
DCRDR relative to this concern (341/880021-03 (DRP)).
d.
At 0020 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, July 23, 1988, with the reactor at approximately
90 percent power, a power reduction / shutdown was initiated due
to increasing Drywell (0/W) unidentified leakage.
At 0106 hours0.00123 days <br />0.0294 hours <br />1.752645e-4 weeks <br />4.0333e-5 months <br />,
calculated D/W unidentified leakage exceeded the Technical
Specification limit of 5.0 gpm (actual 5.4) and at 0505 hours0.00584 days <br />0.14 hours <br />8.349868e-4 weeks <br />1.921525e-4 months <br />,
in accordance with the licensee's approved Emergency Plan, an
Unusual Event was declared. At 1516 hours0.0175 days <br />0.421 hours <br />0.00251 weeks <br />5.76838e-4 months <br />, the reactor was
manually scrammed from 10 percent power.
The licensee subsequently
determined the source of the leakage as the RCIC Inboard Steam
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Supply Isolation Valve and the RWCU vessel drain line valve (G33-F100).
The inspector observed various stages of the reactor S/D and verified
licensee actions as being in accordance with Technical Specifications.
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During the react)r shutdown, the inspector discussed the following
issues with the ifcensee:
(1) Drywell de-inerting via the Torus-to-Orywell vacuum Breakers.
Whilo at approximately 10 percent power, the licensee planned
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to enter the D/W and investigrte the source of the leakage.
Failure to de-inert the D/W due to an inoperable T4803-F602
"D/W Exhaust Inboard IsolatNn Valve," rendered D/W access
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wcile in Modes 1 and 2 impos e le.
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Due to the inoperative F602, Primary Containment was inerted
on May 17, 1988, via the process of opening the D/W to torus-
vacuum breakers (refer to Inspection Report No. .50-341-88012)
and adding nitrogen to the torus free air space.
Inerting the
Drywell via this flow path is discussed in a note to Technical
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Specification 3.6.4.1 which allows:"the suppression chamber
Drywell. vacuum breakers be manually opened for.inerting
containment," but does not state the appropriateness of
this flow path to de-inert.
The Office of Nuclear Reactor
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Regulation (NRR) was. contacted for an interpretation of this
noie.
NRR's interpretation was that under the current 3.6.4.1
Technical Specification, the Drywell-to-Torus' vacuum breakers
will not be used during the de-inerting process.
This
interpretation was discussed with, and acknowledged by
the licensee.
(2) Requirement for Containment Airborne Particulate Monitoring.
During the reactor S/D, the inspector questioned an apparent
disciepancy between the UFSAR Appendix A, Technical
Specifications, and Regulatory Guide 1.45 regarding airborne
particulate monitoring of the primary containment atmosphere.
The UFSAR states that in accordance with Regulatory Position 3
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of Regulatory Guide 1.45, containment monitored parameters
include, but are not limited to, sump level, sump level flow,
and airborne particulate rates.
In actuality, no on-line
containment ] articulate monitor exists.
Further investigation
determined t1at a July 1981 Fermi Safety Evaluation Report
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(SER), NUREG-0998, discussed on Pages 5-18 and 5-19 the subject
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of leakage monitoring.
The SER acknowledged that monitoring of
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airborne particulate is not performed, but that other systems
being used are sufficient to meet the intent of Regulatory
Guide 1.45.
The other systems used to monitor for leakage
are (1) sump level and flow monitoring, (2) a supplementary
Drywell sump level monitor, and (3) airborne gaseous
radioactivity monitoring.
The inspector concluded that the above monitoring methods with
the stated alternative comply with the intent of Regulatory
Guide 1.45.
Additionally, pressure temperature, and humidity
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measuringdevicesarealsousedtoIndicatetheexistenceof
leakage.
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The licensee identified to the inspector that a clarification
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of the UFSAR was previously identified as documented in
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UFCN 88-068 drafted June 7, 1988.
UFCN 88-068 was reviewed
by the inspector and it adequately addressed the requi'ed
clarification and was currently in the normal approvai
process.
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(3) Weaknesser, in the coordination in determining the leakage
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source. The licensee also recognized that the organizational
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response to leaks needed improvement in the radiochemistry
analysis area and the communication of that analysis to the
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JN'SS and plant management.
Numerous procedure changes were ,
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enacted to provide clearer direction to personnel taking the
samples and what to evaluate the samples for and from what
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location samples should be extracted.
Personnel were briefed-
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on thir, event to provide a stronger perspective as to what is
needed.
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No violations or deviations were identified in this area
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4.
Monthly Maintenance Observ'ation (62703)
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Station maintenance activities on safety-related systems.and components
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listed below were observed to ascertain that they were conducted in
accordance with approved procedures, regulatory guides and industry
codes or standards and in conformance with Technical Specifications.
The following items were considered during this review:
the limiting
conditions for operation were met.while components or systems were
removed from service; approvals were obtained prior to initiating the
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. ork; activities were accomplished using approved procedures and were
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' inspected as applicable; functional testing and/or calibrations were
performed prior to returning components or systems to service; quality
control records were maintained; activities were accomplished by
qualified personnel; parts and materials used were properly certified;
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radiological controls were implemented; and fire prevention controls
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were implemented.
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Work requests were reviewed to determine the status of outstanding jobs
and to assure that priority is assigned to safety-related equipment
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maintenance which may affect system performuce.
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The following maintenance activities'were observed:
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Troubleshoot and repair Drywell Exhaust Inboard Isolation
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Valve T4803-F602 (WR 02280517).
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Troubleshoot.and repair Drywell Vent / Inboard Isolation
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Valve T4803-F601 (WR 00180728).
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Leak repair to RCIC steam supply inboard Isolation
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Valve E61-F007.
Troubleshooting of B Recirculation pump discharge
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Valve B31-F0318 failure to close from the Control
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Room (WR 00380828).
Troubleshooting activities into the cause of the scram of
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24 control rods (WR 002B0802).
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Following completion of maintene ce on tiie RCIC valve, the inspectors
verified that the system had bevi returned to service properly.
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While observing post-maintenance testing on the High Pressure Coolant
Injection (HPCI) System, the inspector noted the verification of
system operability was conducted using certain sections of Operating
Procedure 23.202, "High Pressure Coolant Injection System." However,
since 23.202 is a system operating procedure and provides no step-by-step
signoff of the activities the control room operator needed to do as part
of the test, the operator with the concurrence of the Nuclear Assistant
Shift Supervisor (NASS) utilized appropriate portions of Surveillance
Procedure 24.202.01, "HPCI Pump Operability and Flow Test at 1000 psig
and Valve Operability" to document the test performance.
The decision
to do this was made at the time the test was tc be performed and
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subsequently resulted in the operator working with two procedures
simultaneously; 23.202 to conduct the test and 24.202.01 to document the
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test.
The inspector had two concerns with this approach.
First, the use
of two procedures simultaneously to perform testing could lead tc confusion
on the part of the operator.
Second, due to the lack of specific
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instructions or preplanning provided by the work package to properly
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conduct the test, the operator (with the NASS) developed, on the spot,
a means of conducting a test by using segments of two existing procedures.
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The licensee recognizes the potential for error using such an approach to
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testing and is currently evaluating whether alternate methods may be
better suited in the future.
This is considered an open item pending
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completion of licensee actions (341/88021-04(DRP)).
No violations or deviations were identified in this area.
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5.
Monthly Surveillance Observation (61726)
The inspectors observed surveillance testing on the high pressure cooling
system per Procedure 24.202.01, "HPCI Pump Operability and Flow Test at
1000 psig and Valve Operability" required by Technical Specifications and
verified that:
testing was performed in accordance with adequate
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procedures, test instrumentation was calibrated, limiting conditions
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for operation were met, removal and restoration of the affected components
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were accomplished, test results conformed with Technical Specifications
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and procedure requirements and were reviewed by personnel other than the
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individual directing the test, and any deficiencies identified during the
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testing were properly reviewed and resolved by apropriate management
personnel.
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The inspectors also witnessed portions of the following test activities:
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24.413.03
Control Room Emergency Filter Monthly Operability
Test.
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24.404.02
SGTS Filter Ponthly Operability Test.
No violations or deviations were identified in this area,
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6.
Followup of Events (93702)
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During the inspection period, several events occurred, some of which
required prompt notification of the NRC pursuant to 10 CFR 50.72.
The
inspectors pursued the events onsite with licensee and/or other NRC
officials.
In each case, the inspectors verified that the notification
was correct and timely, if appropriate, that the licensee was-taking
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prompt and appropriate actions, that activities were conducted within
regulatory requirements and that corrective actions would prevent
future recurrence. The specifit, events are.as follows:
50.72 Events
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July 19, 1988
ESF actuation when RPS "B" EPA breaker opened
and deenergized RPS Bus "B".
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July 21, 25,
Reports on inaccessible or unsatisfactory
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26, 28 and
testing of flanges from West Jersey
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August 4, 1988
Manufacturing Company.
July 23,1988
Determined unidentified drywell leak based on
30 minute sample of 5.4 gpm.
Reduced reactor
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power; leak based on one hour sample of 5.6 gpm.
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Unusual event declared.
July 23, 1988
Reactor placed in shutdown condition by manual
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scram due to unidentified leakage in drywell.
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July 24, 1988
Terminated unusual event.
Preparing to place
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plant in shutdown cooling.
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July 25, 1988
Retractio1 of April 9,1988, event report af ter
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being determined not reportable.
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July 27, 1988
FSF actuation when I&C repairman shorted across
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two terminals and caused an auto initiation of
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Div 1 EECW.
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July 27, 1988
HPCI E41 F006 valve open circuit grounded
preventing operation.
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August 14, 1988
Trip of main turbine generator causing a reactor
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August 21, 1988
Declaration of Unusual Event and initiation
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of a plant shutdown due to recirculation Pump B
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discharge valve being inoperable.
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August 22, 1988
ESF actuation when RWCU system pumps tripped
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on low flow.
G33-F001 and G33-F001 valves
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closed upon receipt of delta flow isolation
signal.
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August 28, 1988
Declaration of Unusual Event and initiation of
a plant shutdown due to recirculation Pump B
discharge valve being inoperable.
On July 25, 1988, via the ENS, the licensee retracted the April 9,
1988, 10 CFR 50.72 event notification on loss of RHR cooling which
occurred when the shutdown (S/D) cooling injection valve (E11-F015B)
automatically closed.
The licensee determined this event was not
reportable because the closure signal for the F015B valve did not
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originate from ESF logic.
The inspector discussed with the licensee
that although the event was not reportable as an ESF activation, the
event is reportable as loss of residual heat removal.
The inspector
noted under 50.72 (b)(2)(iii)(B), that any event that alone could have
prevented the fulfillment of the safety function of' structures or systems
that are needed to remove residual heat is reportable as a four-hour
report.
The inspector identified two additional items that raise the
significance of this event:
(1) the loss of S/D cooling on the "B" loo
occurred at a time when the "A" loop of 5/D cooling was out-of-service,p
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(2) the loss of S/D cooling occurred for 30-35 minutes prior to being
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identified by the control room operators.
Following the discussions,
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the licensee agreed to submit an LER on the event.
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Following the main turbine trip that occurred on August 14, 1988, the
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inspector noted that credit was taken for performance of Surveillance
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Procedure 24.109.001 "Turbine Steam Valves Weekly Test" due to the event.
When questioned about the advisability of doing this, licensee management
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responded that a review was performed at the time and the Technical
Specification surveillance requirements which POM 24.109.001 implements
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were verified as having been met.
Additionally, it was stated that this
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was not the first time this philosophy was implemer+ed and that the
licensee intended to continue the practice.
The in vector expressed
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concern that a surveillance procedure may address surveillance
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requirements / commitments beyond those in Technical Specifications and
as such, if credit is to be taken for performance of a surveillance as
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a result of an operational event, all portions of the procedure need
addressingIonsurveillancerequirements.not just those portions directly relating t
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Specificat
The inspector reviewed
24.109.001 and, in that case, found no additional requirements beyond
those the licensee had verified in accordance with the Technical
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Specifications.
However, the inspectors will continue to review
this practice as future examples occur.
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Deviation Report Events
The inspector revieved DER 88-1520 which identified that a HPCI
discharge valve had not been tested at the required time interval for
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alert testing.
Thr6 inspector confirmeo through discussion with licensee
perronnel that the ASME Section XI for valve testing had not been
proporly implemented for the HPCI discharge valve.
The inspector
evaluated this violation to 10 CFR 2, Appendix C V.G. and determined:
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The violation was identified by the licensee,
b.
The violation did not render the HPCI system incapable of
injecting the required water flow into the reactor vessel
in the required maximum permissible time frame,
c.
At the end of the inspection period the time frame for
LER submittal had not expired.
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d.
Corrective actions were still being formulated.
e.
A violation of similar nature had not occurred in the
last two years.
This matter is considered unresolved (341/88021-05) contingent upon
corrective action review and LER submittal.
No violations or deviations were identified in this area.
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7.
Licensee Event Reports Followup (92700)
Through direct observations, discussions with licensee personnel,
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and review of records, the following event reports were reviewed to
determine that reportability requirements were fulfilled, immediate
corrective action was accomplished, and corrective action to prevent
recurrence had been accomplished in accordance with Technical
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Specifications,
a.
(Closed) LER 88002:
Main steam line radiation monitor surveillance
procedure inadequacy causes MSIV closure.
This event which was
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described in detail in Inspection Report No. 50-341/88003 was caused
by accidental snorting of a fuse in the MSIV DC logic while changing
another adjacent fuse.
The I&C technician who replaced the fuse
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was not awsre that the circuit needed resetting and the MSIV DC half
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closure trip logic was in effect when a surveillance to check the
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functioning of the high radiation closure of MSIVs was started the
following day.
The technician performing this test misinterpreted
the step in the procedure to verify that amperage was present on
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both the DC and AC circuits before proceeding.
The actions taken
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to prevent recurrence of this condition were threefold.
First,
surveillance procedure 44.101.028 was revised to assure that there
is current on both the AC and DC circuits if the HSIVs are open;
this has been completed by Revision 22 to the abcVe procedure.
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In addition, 52 of the MSIV surveillance procedures were revised
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to remove similar ambiguities.
The second corrective action was
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to place labels on Panels R325064B and R3250618 to indicate that
Circuits 2 and 11 power MSIV logic and to notify the Nuclear Shift
Supervisor if they are or have been deenergized.
The inspector
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verified the installation of the labels.
The third corrective
action was to improve I&C technician training.
The "lessons
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learned" from this event were reviewed by all I&C personnel;
and in addition, after reviewing the I&C training program, it
was decided that:
(1) I&C training course CP-IC-336 would be implemented in
August 1988.
(2) The on-the-job I&C course, CP-IC-331 would be revised to include:
(a) emphasizing the initial conditions prior to testing,
(b) actions to be taken if initial conditions cannot be met,
and (c) action to be taken when one channel inadvertently trips
while testing the other channel.
This course is to be complete
by the end of 1988.
(3) The I&C repairman oualification program description, PD-IC-720,
will be revised to mandate completion of 1 above and applicable
portions of 2 above prior to performing surveillances.
This
change is in the approval chain.
Since the corrective actions appear to be adequate to prevent
recurrence of this type of event the LER was closed; however,
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the completion of the I&C training will remain an open item
(341/88021-06) until the changes to the training program have
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been completed.
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b.
(Closed) LER 88003:
Setpoints and Head Correction incorrect for
Residual Heat Removal (RHR) Interface Valves.
During a review to
verify pressure monitor setpoints in response to a previous
violation (87006-01) and the I&C surveillance procedure improvement
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program, the pressure alarm setpoints in TS 3.4.3.2-2 RHR Low
Pressure Cooling Injection and RHR Shutdcwn Cooling were found to
be higher than the relief valve settings.
On January 6, 1988, the
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licensee proposed an emergency TS change to lower the alarm setpoints
and on the same date a TS Temport ry Waiver of Compliance was issued
by NRR.
On January 13, 1988, Amendment No. 14 was issued which
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changed the setpoint in Tables 3. 4.3.2-2.
In reviewing the
surveillance procedures for functional and calibration checks
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of these pressere alarms, the inspectors found that the procedures
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had been revised to include the adjusted setpoint pressures.
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c.
(Closed) LER 86027:
Vacuum Breaker Valve Failure.
Followup to
this LER was previously documented in Inspection Report No. 87022.
As a result of that review, violation 87022-01 was issued.
The
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violation corrective actions are adequate to complete followup on
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this LER.
Therefore, this LER is closed and the final corrective
actions will be inspected in the followup to violation 341/87022-01,
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d.
(Closed? LER 85080-01:
Failure to place a radiation monitor
in serv <ce while re Masing liquid effluent.
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In addition to the review criteria stated above, the LERs were reviewed
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for potential violations of regulatory requirements.
The results of
that review identified that a violation of Limiting Conditions for
Operation was associated with LER 85080-01.
This violation occurred
during the same time frame and was of the same type as the violations
identified in Inspection Report No. 50-341/85040.
As indicated in
Paragraph 9.d. of Inspection Report No. 50-341/86019, the escalated
enforcement actions of Inspection Report No. 50-341/85040 adequately
address this violation and no citation will be given,
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No oth6r violations or deviations were identified in this area.
8.
Startup Test Observation (72302)
The inspectors reviewed portions of startup test procedures, toured the
areas containing system equipment, interviewed personnel, and observed
test activities.
While observing startup tests the inspector verified
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that the established testing prerequisites were met, testing was performed
in accordance with adequate procedures, limiting conditions for operation
were met, test personnel were knowledgeable of the test, data was
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accurately taken, and special test equipment required by the procedure
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was calibrated and in service.
Th inspector observed the performance of the following startup tests:
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STUT 03B.023
Feedwater System level Setpoint Changes.
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STUT 06B.030
Recirculation System One and Two Pump Trips.
STUT 06C.016
Selected Process Temperatures - Recirculation Pump
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Trip Data.
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STUT 04B.019
Core Performance - Process Computer Determination.
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STUT 04A.030
Recirculation System - System Performance.
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During performance of STVT 068.030 on August 21, 1988, attempts to
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close reactor recirculation Pump B discharge valve (B31-F0B18) were
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unsuccessful and the licensee commenced a reactor shutdown in
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accordance with Technical Specifications and entered the Emergency
Plan.
Suts,quently, troubleshooting of the motor operator revealed
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three loose terminations to the valve's torque switch.
The terminations
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were tightened, the valve tested and found to stroke properly, and the
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unit returned to power.
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On August 28, 1988, test conditions were reestablished to complete
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STVT 06B.030.
Again when B31-F031B was directed to close from the
thevalvefailedtostroke.
The reactor was shutdown,
control room}ng of the sotor operator was conducted, and torque switch
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troubleshoot
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settings found to be incorrect.
Two NRC Region III inspectors were
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subsequently dispatched to the site to review licensee corrective
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actions (Reference Inspection Report No. 341/88025(DRS)).
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The inspector also reviewed the completed results of STVT 06B.019,
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Core Performance - Process Computer Determination, and determined
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that the test was satisfactory.
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No violations or deviations were identified.
9.
Personnel Qualifications
During the inspection pericd, the licensee changed the "Engineer in
Charge." The new individual is holding this position until a permanent
replacement is acquired.
The interim individual's qualifications were
reviewed against the applicable ANSI 18.1 standard revision and found
to meet the qualification requirements.
No violations or deviations were identified.
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10.
Regional Requests
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During the inspection period, the inspector continued to pursue the
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regional request dated September 24, 1987, dealing with preventive
maintenance activities associated with the GE AKF-2-25 circuit breakers,
previously discussed in Inspection Report No. 341/88006.
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Deviation Event Report DER No. 88-0290 was istJed tc address the corJerns
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noted in the above report that were contrary
?.: recommendations in
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NRC Information Notice 87-12 and GESIL 448.
a.
The breaker inspections were scheduled '.or every other refueling
instead of annually or every refueling.
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b.
There were no plans to disassemble and overhaul the breaker at
five year intervals.
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The inspectors found that Maintenance Instruction MI-M037, Rev 2,
Recirculation Pump Generator Field Breaker (GE Type AKF) General
Maintenance, had been approved March 14, 1988.
This procedure deals with
the cleaning, inspection, lubrication, adjustment and operational checks
of the AKF type breakers.
The revision included the SIL recommendations
concerning approved lubricants.
The other recommended actions of the SIL
above had not been addressed so this will be carried as an Open Item
(341/88021-07).
11.
Review of Allegations
(Closed) Allegation No. RI11-88-A-0022:
Concerns regarding the process
for updating the Updated Final safety Analysis Report (UFSAR).
On
February 16, 1988, the Senior Resident Inspector was contacted by an
anonymous alleger who provided four allegations regarding the UFSAR
updating process as outlined below:
Allegation 1:
There was no revjew or approval by Licensing of changes
to the FSAR when it was updated the first time.
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Allegation 2:
Anyone can change the UFSAR based on filling out a form.
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These forms receive no review before incorporation into
the UFSAR.
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Allegation 3:
The form specified in interfacing Proceoure 11.000.121
is not the correct form to be used.
A lady in Licensing
informed the alleger not to use that. form but to use
another form not approved that'has been made up by
Licensing.
Allegation 4:
The alleger was told by a supervisor not to write a DER
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on this situation and that the supervisor did not want
any DERs associated with the UFSAR update activities.
The alleger indicated that if the alleger wrote a DER
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there would be adverse personnel action taken against
him/her.
The NRR Project Manager conducted a review of the FSAR change files and
the program, including directives and procedures, implemented by the
licensee to implement FSAR changes.
Discussions were conducted with
the cognizant Licensing personnel.
For the first FSAR update, Procedure NOIP-11.000.121-NS, "Updated Final
Safety Analysis Report and Environmental Peport Revisions," Revision 3,
issued in 1985, was-used to provide input to Licensing on proposed FSAR
changes.
This procedure contains a form entitled, "UFSAR Change Notice
(UFCN)," which provides blocks to describe the change, the basis for the
change, and who initiated, reviewed and approved or concurred in the
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change.
The form provides space for several approvals in Block 8; however,
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a review of the first FSAR update UFCN forms on file indicated that the
forms did not always reflect those approvals because the procedure did
not mandate that Block 8 must be completed.
However, the UFCNs on file
did have documents attached to them which indicated who had reviewed and
approved the changes reflected on the form.
The reviews were conducted
by Engineering, Operations, Licensing and the Independent Safety
Engineering Group (ISEG).
Engineering usually initiated the change
proposal, but others were not prohibited from doing so.
The QA
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organization does not review UFCNs.
The ISEG reviewed those change
packages which contained safety evalustions (SEs) since, procedurally,
ISEG reviews all SEs whether associated with an FSAR change or other
plant change.
The FSAR change initiator does not get involved in ths
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proposed change review process, unless the matter is technically
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complicated, c9ntroversial, or the initiator is questioned by ISEG
during the SE review.
The proposed FSAR change must be accepted by
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the initiator's first line supervisor before it is sent to Licensing.
The UFCNs received by Licensing are sent to a Subject Matter Expert
(SME) who is responsible for reviewing the change for technical ade
and necessity, and who usually finalizes the SE which ISEG reviews.quacy
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SHE is the individual assigned responsibility for a specific section of
the UFSAR.
N0!P-11.000.121, Revision 4, dated February 1988, is the current procedure
in use for making UFSAR changes for the second update.
This revision
mandates that approvals be reflected in Block 8 of the UFCN.
Licensing
is now playing a greater role in reviewing and assessing the technical
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adequacy of proposed changes.
For the first update, contractor support
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was more extensively used to provide the Licensing overview.
A review
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of FSAR change packages processed for the second update indicates an
improvement over the packages oa file for the first update.
The FSAR change program and related procedures are undergoing further
changes as part of the licensee's effurts to upgrade the quality and
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accuracy of plant procedures.
Directive FMD-RA2, "Licenses, Plans, and
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Programs," Revision 0, issued in January 1988, establis.es requirements
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for control of amendments to licenses, plans, and programs, and as;igns
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responsibility for implementing those requirements, which includes the
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annual update of the FSAR.
Under the new system a procedure will be
issued,FIP-RA201-SQ,"AmendmentstotheOperatIngLicense,UFSAR
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and NRC Approved Plans and Programs." This will replace
Procedure N0!P-11.000.121.
Licensing has in place a data table for
tracking FSAR changes which will be enhanced to reflect the new system.
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The licensee expects to have the new programmatic and procedural changes
related to the FSAR updates luplemented by fourth quarter of CY 1988.
NRC Conclusions:
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Allegation 1:
Licensing does not approve FSAR changes.
Licensing
coordinates and keeps trcck of propostd changes and
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assures that appropriate approvals are obtained before
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Deing incorporated in the FSAR.
There was no evidence
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that the changes incorporated in the first FSAR update
did not receive appropriate reviews and were not
approved.
This allegation was not substantiated.
Allegation 2:
It is true that anyone can initiate a FSAR changa and
the UFCN form is used for that purpose.
However, the
change requires first line supervisor acceptance before
it gets into the system. When received by Licensing,
it is directed to the SME for review to ensure that
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the proposed change is acceptable.
The fact that
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anyone can change the FSAR was substantiated; however,
the proposed change is reviewed and approved before
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incorporation as concluded under Allegation 1.-
Allegation 3:
It is true that the interfacing procedure and UFCN
form have undergone a few revisions; however, there
was no evidence that any unapproved form or procedure
was used in the FSAR updating process.
This
allegation was not substantiated.
Allegation 4:
The NRC did not pursue this allegation in that the
alleger was anonymous and did not identify the supervisor
involved.
The DER procedure in effect on February 2,
1988, was FIP-cal-01-SQ, Revision 0, "Deviation and
Corrective Action Reporting." Paragraph 2.1.1 requires,
in part, that procedural noncompliance including
violations of procedures having nuclear safety significance,
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be documented as a DER.- It is noted that the DER originator
and his supervisor are required to sign the DER.
Issuance
of a DER would not have been appropriate in this case in
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that no procedural noncompliance was idertified.
No violations or deviations were identified.
11. Unresolved Items
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Unresolved items are matters aboat which more information is required
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in order to ascertain whether they are acceptable items, violations
or deviations.
An unresolved item disclosed during the inspection
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is discussed in Paragraph 6.
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12. Open Items
Open items are matters which have been discussed with the licensee,
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which will be reviewed further by the inspector, and which involve some
action on the part of the NRC, or licensee, or both. Open items disclosed
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during the inspection are discussed in Paragraphs 3, 4, 7 and 10.
13.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on September 20, 1988, and informally throughout the inspection period
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and summarized the scope and findings of the inspection activities.
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The inspectors also discussed the likely informational content of the
inspection report with regard to documents or processes reviewed by the
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inspectors during the inspection.
The licensee did not identify any
such documents / processes as proprietary.
The licensee acknowledged
the findings of thc inspection.
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