ML14178A054
| ML14178A054 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 11/07/1990 |
| From: | Carroll R, Garner L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14178A052 | List: |
| References | |
| 50-261-90-22, NUDOCS 9011160172 | |
| Download: ML14178A054 (16) | |
See also: IR 05000261/1990022
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/90-22
Licensee: Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.:
Facility Name: H. B. Robinson
Inspection Conducted:
September 11 - October 10, 1990
Lead Inspector:
fLAe.I'
/ /
L.'W. Garner, Senior Resident Inspector
D te S gne
Other Inspector: K. R. Jury
Approved by:____
. E. Carroll, Acting Section
ief
atE Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation, onsite
followup of events, written reports of nonroutine events,
and action on
previous inspection findings.
Results:
Release of Freon R-22 gas into a vital area resulted in an Alert declaration.
Incorrect determination that the affected area was a protected area resulted in
improper initial event classification as an Unusual Event. Based upon previous
inspection.findings, the improper classification was a violation for failing to
correct an exercise weakness as required by 10 CFR 50, Appendix E (paragraph 5).
Two examples of a violation for failure to properly implement procedures were
identified.
One example involved valve mispositioning which resulted in
draining 8,000 gallons of spent fuel pool water to the containment sump. The
.other
example was the discovery that the primary air and back-up nitrogen
supplies to the cavity seal were isolated after vessel defueling with the
cavity still flooded (paragraph 2).
9011160172 901107
PDR ADOCK 05000261
G
PNU
2
A non-cited violation was identified for failure to implement a procedure, in
that, the state and county emergency operation centers were not contacted when
a Unusual Event notification was made to the warning points (paragraph 5).
A temporary waiver of compliance was granted October 5, 1990, for a one-time
change to Technical Specification 3.5.3.3.
The waiver allowed reactor
containment vessel purging without operable effluent radiation monitors when
containment integrity is not required and there is no fuel in-containment
(paragraph 2).
All 106 guide tube support pins will be replaced this outage as a result of
ultrasonic inspections which identified 38 pins with intergranular stress
corrosion crack indications (paragraph 3).
At least thirteen flexureless guide tube inserts will be installed in locations
which have less than two intact flexures (paragraph 3).
A safety injection pump test into three cold legs resulted in flow rates for
which net positive suction head requirements were not specified (paragraph 7).
Frequent management tours and emphasis on housekeeping have generally resulted
in maintaining housekeeping at an acceptable or above level during the outage.
.
An exception was the reactor cavity area cleanliness during control rod
unlatching commencement(paragraph 2).
Periodic Onsite Nuclear Safety Section distribution of relevant operating
experience feedback reminders prior to significant evolutions was noteworthy
(paragraph 2).
REPORT DETAILS
1. Persons Contacted
- R. Barnett, Manager, Outages and Modifications
C. Baucom, Shift Outage Manager, Outages and Modifications
J. Benjamin, Shift Outage Manager, Outages and Modifications
C. Bethea, Manager, Training
- S. Billings, Technical Aide, Regulatory Compliance
- R. Chambers, Manager, Operations
D. Crook, Senior Specialist, Regulatory Compliance
- J. Curley, Manager, Environmental and Radiation Control
C. Dietz, Manager, Robinson Nuclear Project
D. Dixon, Manager, Control and Administration
J. Eaddy, Supervisor, Environmental and Radiation Support
S. Farmer, Supervisor - Programs, Technical Support
R. Femal, Shift Foreman, Operations
- E. Harris, Manager, Onsite Nuclear Safety
J. Kloosterman, Director, Regulatory Compliance
D. Knight, Shift Foreman, Operations
E. Lee, Shift Outage Manager, Outages and Modifications
A. McCauley, Supervisor -
Electrical Systems, Technical Support
R. Moore, Shift Foreman, Operations
R. Morgan, Assistant to the Manager, Robinson Nuclear Project
D. Nelson, Shift Outage Manager, Outages and Modifications
- M. Page, Manager, Technical Support
D. Quick, Manager, Plant Support
D. Seagle, Shift Foreman, Operations
- J. Sheppard, Plant General Manager
- R. Smith, Manager, Maintenance
R. Steele, Shift Foreman, Operations
D. Winters, Shift Foreman, Operations
- H. Young, Director, Quality Ass-urance/Quality Control
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and office personnel.
- Attended exit interview on October 18, 1990.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Operational Safety Verification (71707)
The inspectors evaluated licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory requirements.
These activities were confirmed by direct observation, facility tours,
interviews and discussions with licensee personnel and management,
verification of safety system status, and review of facility records.
2
To verify equipment operability and compliance with TS,
the inspectors
reviewed shift logs, Operation's records, data sheets, instrument traces,
and records of equipment malfunctions.
Through work observations and
discussions with Operations staff members,
the inspectors verified the
staff was knowledgeable of plant conditions, responded properly to alarms,
adhered to procedures and applicable administrative controls, cognizant of
in-process surveillance
and maintenance activities,
and aware
of
inoperable equipment status.
The inspectors performed channel
verifications and reviewed component status and safety-related parameters
to verify conformance with TS.
Plant tours and perimeter walkdowns were conducted to verify equipment
operability, assess the general condition of plant equipment,
and to
verify that radiological controls, fire protection controls, physical
protection controls,
and equipment tagging procedures were properly
implemented.
Temporary Waiver of Compliance
On October 5, 1990, the licensee .requested an emergency TS amendment and
Temporary Waiver of Compliance from the requirements of TS 3.5.3.3, Table
3.5-7, items 3.a and 3.b required action b.
The waiver request was
verbally granted the same day and subsequently confirmed by letter dated
October 9, 1990.
The waiver was to remain into effect until emergency TS
amendment processing was completed.
The emergency TS amendment was
subsequently issued on October 16, 1990, as amendment no. 130. The waiver
and the amendment authorized purging of the CV without effluent radiation
monitors RMS-11, RMS-12, RM-14 and RMS-34 operable. This was a one time
change for refueling outage 13, applicable only when fuel is not in the CV
and
CV integrity is not required.
Additionally,
CV atmosphere grab
samples are to be taken once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and analyzed for radionoble
gases within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Containment purging during outages is desirable to maintain safe personnel
working conditions.
The need for the waiver and emergency TS change
resulted from the simultaneous installation of two modifications: M-1005,
Upgrade Plant Vent Radiation Monitoring and Stack Flow Monitor,
and
M-1049, Radiation Monitoring System Upgrade. The latter modification was
initiated in the third quarter of 1989 by a system team to improve the
overall system reliability.
In either March or April 1990, engineering
identified that CV purging would not be allowed by TS 3.5.3.3, Table
3.5-7, item 3.a and 3.b required action b, if
RMS-11,
12,
14, and 34 were
simultaneously removed from service.
As
a result of an interdepartmental
miscommunication,
engineering
proceeded with development of M-1049 in conjunction with M-1005 such that
these monitors would be simultaneously inoperable without initiating
actions to obtain relief. On July 31, 1990, this oversight was discovered
and discussed by the PNSC. Alternate installation options to maintain at
least one of the monitors in service were reviewed; however, they were not
considered feasible due to the relatively short time available to perform
3
necessary major changes in the modification packages.
If an appropriate
TS change request had been promptly submitted subsequent to initial issue
identification, a waiver and emergency TS amendment would not have been
required.
Prior to October 5, 1990,
NRR recognized that the replacement high range
noble gas effluent monitor had a maximum detection range one decade less
than the existing monitor. The existing monitor met the maximum detection
range (100,000 microcuries per cubic centimeter) required by the March 14,
1983 order confirming licensee commitments on post-TMI related issues.
The required maximum range was specified in NUREG-0737,
item II.F.1-1.
Subsequently,
the licensee revised the modification to increase the
maximum detection range for the replacement monitor to be in compliance
with the above order.
Based upon commitments to RG-1.97, Instrumentation
For Light-Water-Cooled Nuclear Power Plants To Assess Plant And Environs
Conditions During and Following An Accident, revision 3, the licensee had
improperly determined that item I.F.1-1 was no longer applicable. At the
end of the report period, the licensee was reviewing if similar problems
exist with other modifications.
This is an URI:
Review If TMI Item
Commitments
Have Been Improperly Superseded by RG-1.97 Commitments,
90-22-01.
Inadvertent Draining Of SFP Water
On September 22, 1990, during performance of GP-009, Filling,
Purification,
and Draining of the Refueling Cavity, revision 9, an
operator inadvertently opened valve WD-1757C,
which is the lower cavity
drain to the CV sump.
As a result, approximately 8,000 gallons of SFP
water was subsequently discharged into the CV sump.
This procedure was
being performed in preparation for performance of EST-030,
Fuel Handling
Equipment Interlock and Operation Test, and prior to initial cavity fill.
Valve WD-1757C is located in the excess letdown heat exchanger room which
is a locked high radiation area, and is covered with lead blanketing for
shielding purposes.
Valve operation is by means of a reach rod through
the room's door and the valve is reverse acting (i.e., clockwise to open),
which is a different operation than almost all valves at HBR.
Valve
WD-1757C is a ball valve with movement limited by mechanical stops.
This valve mispositioning was discovered on September 23,
1990, when an
increase in CV sump level was noticed on the RTGB after the SFP gate valve
was opened; operations then verified the sump level increase in the CV.
The SFP gate valve was subsequently closed and WD-1757C was discovered
open.
Valve WD-1757C was then closed and CV sump level stabilized.
SCR 90-071 was initiated to document this event and determine root cause,
including performance of an HPES evaluation. Failure to correctly operate
valve WD-1757C as required by GP-009 was
identified as a violation:
Failure To Adequately Implement Procedures As Required By TS, 90-22-02.
4
Pneumaseal Supply Air Isolation
On October 8, 1990, during routine CV inspections, operations personnel
discovered both the primary air and back-up nitrogen gas supplies isolated
to the pneumaseal while the cavity was flooded. The pneumaseal provides
the inflatable seal between the reactor vessel flange and the reactor
cavity.
The seal, which prevents leakage of refueling water from the
cavity, was installed per WR/JO 90-AEJI1 on September 22,
1990,
in
preparation for flooding the cavity for refueling operations. Based on a
review of Combustion Engineering's Field Activities Log,
adequate air
supply to the seal was verified as late as October 2, 1990 (i.e.,
subsequent to the vessel being defueled).
The licensee initiated SCR 90-077 to document the incident and determine
root cause.
Maintenance Refueling Procedure MRP-001, Pneumaseal
Installation and Removal,
revision 3, Step 7.2.9, required that the
instrument air and nitrogen supply valves be wired open and a warning sign
be provided so that air and the nitrogen supplies would not be interrupted
while the pneumasel was in service.
Evidently, at some time between
October 2 and 8, 1990, the supply valves were closed, resulting in the
isolation of supply air and nitrogen.
Per MRP-001, prior to pneumaseal
installation, the seal is to be inflated and leak checked with
verification that the seal maintains pressure for fifteen minutes with the
supply air and nitrogen isolated.
There are check valves installed
downstream of the manual
supply valves to prevent back-leakage.
Additionally, in 1984 and 1985,
pnemaseal tests were conducted to ensure
the seal could not be physically maneuvered through an opening equivalent
to the size of the opening between the vessel flange and cavity with the
cavity flooded. This testing was conducted in response to IEB 84-03 which
was generated as a result of the pneumaseal failure at Haddam Neck.
The
testing demonstrated that the seal would not fail even if it was deflated.
As such, even with seal air and nitrogen supplies isolated, seal failure
was not expected and did not occur.
However, failure to maintain the
instrument and nitrogen supply valves open as required is considered
another example of violation 90-22-02.
During review of MRP-001,
the inspectors noted that there are no
procedural sign-offs nor were acceptance criteria provided within the
procedure to document acceptable pneumaseal pre-installation testing and
installation. Procedure MRP-001 was revised in August 1990 as part of the
Maintenance Procedure Upgrade Program. Based on the fact that neither the
procedure nor the WR contained sign-offs verifying certain steps within
the procedure were adequately performed,
it
was difficult to ascertain
that seal testing and installation was completely performed as specified.
This lack of acceptance criteria and verification sign-offs was considered
a procedural weakness.
Vital Power Availability During Refueling
The inspectors verified that from the time the reactor was shut down on
September 8, 1990, until all fuel was removed from the reactor vessel,
both.RHR pumps and associated heat exchangers were operable with the vital
busses energized from the SAT. During this period, at least one EDG was
5
maintained available.
During the majority of this period, both EDGs and
the dedicated shutdown DG were available.
In addition,
two SI pumps,
though de-energized per TS, were available for service. It was noted that
the licensee has conservatively elected to schedule fuel loading with both
emergency busses operable, even though it is allowable to load fuel with
only one emergency bus available.
Midloop/Reduced Inventory
All work activities which would require reduced inventory operations was
scheduled to be performed with the reactor vessel defueled (i.e., reduced
inventory operation was not scheduled during refueling outage 13).
As a
result, the licensee had no need to review their controls or administra
tive procedures governing reduced inventory operation. However, in case
reduced inventory operation becomes necessary during the outage, the
inspectors verified that procedures were available which adequately
address items 3.a through 3.f listed in TI 2515/101, Loss of Decay Heat
Removal (Generic Letter No.88-17). 10 CFR 50.54(F).
Specifically, the
inspectors verified that the current revisions of GP-008, Draining the
Reactor Coolant.System, revision 20, and OMM-030, Control of CV Penetra
tions During Mid-Loop Operation,
revision 1, contained the proper
precautions and instructions. A similar inspection was documented in IR
89-08.
The inspectors discussed with the licensee that contingency plans
had not been established to repower vital busses from an alternate source
if the primary source were lost during reduced inventory operations. If
reduced inventory operation becomes necessary, the inspectors will review
the proposed plant configuration and discuss with the licensee the need,
if any, for power restoration contingency plans.
Outage Status
At the end of the inspection period, the outage was on schedule with
modification M-994, Control Room Habitability, the critical path activity,
as was anticipated. Obtaining sufficient Q-list fasteners and refrigerant
tubing for M-994 continued to be a challenge.
Reactor defueling was
completed on October 1, 1990.
Fuel reload is scheduled to begin on
November 8, 1990 (i.e., subsequent to the scheduled completion of S/G eddy
current testing and restoration of both E-1 and E-2 emergency busses to
service).
Organizational Changes
On September 24, 1990, Mr. J. J. Sheppard, Manager - Operations, replaced
Mr.
R. E. Morgan as the Plant General Manager.
Mr. R. H. Chambers,
Technical Support Supervisor - Plant Performance, was promoted to
Manager - Operations. Mr. R. E. Morgan has accepted a position as Manager
-
Nuclear Assessment, Harris Nuclear Project.
6
OEF Activities
Inspection Report 90-11 documented that prior to the May 1990 transformer
upgrade outage, ONS conducted a pre-outage, Focus on Safety meeting. The
meeting centered on review of the defined work scope and potential safety
concerns based upon OEF reports.
Prior to refueling outage 13,
sponsored a similar meeting,
and has periodically issued OEF reminders
prior to significant evolutions.
For example, on October 10, 1990, OEF
reminder #4 was issued prior to SW system, turbine, S/G sludge lancing,
and S/G eddy current test work. This reminder included descriptions of:
foreign objects in S/Gs (IEN 88-06); main turbine blade damage caused by
foreign objects left in turbines (SER 86-07); loss of reactor coolant
inventory while in a shutdown condition (IEN 90-55); release of slightly
contaminated material offsite (POER 87-17); and a HPES report involving
consequences of using unclear procedures.
This effort is considered
noteworthy, in that it emphasized management's commitment to learning from
industry experiences such that similar problems are avoided.
Management Tours
Plant management, including unit managers and shift outage managers, have
made frequent tours of the facility, including the CV,
since refueling
outage initiation. This effort has resulted in high management visibility
at job sites and housekeeping has been generally maintained at or above
acceptable levels.
One exception was the reactor cavity area cleanliness
at the start of control rod unlatching. The inspector noted rubber gloves
and a partially torn step-off pad with duct tape within the roped off area
around the cavity. Cloth towels and a roll of duct tape were observed on
the refueling bridge without being secured. The inspector also observed
that items such as tools were being passed in and out of the area without
any apparent accountability.
At the time the inspector made these
observations, a unit manager also observed similar poor conditions and
directed that these conditions be corrected prior to resuming work.
Subsequently, work in the refueling cavity was again discontinued until
the exclusion area was more clearly delineated and additional work and
tool controls were established.
This item was discussed with the
Operations Manager.
One violation, with two examples, was identified.
3. Monthly Surveillance Observation (61726)
The inspectors observed certain safety-related surveillance activities on
systems and components to ascertain that these activities were conducted
in accordance with license requirements.
For the surveillance test
procedures listed below, the inspectors determined that precautions and
LCOs were adhered to, the required administrative approvals and tagouts
were obtained prior to test initiation, testing was accomplished by
qualified personnel in accordance with an approved test procedure, test
instrumentation was properly calibrated, and the tests were completed at
the required frequency. Upon test completion, the inspectors verified the
recorded test data was complete, accurate, and test discrepancies were
7
properly
documented
and rectified.
Specifically, the inspectors
witnessed/reviewed portions of the following test activities:
Safety Injection Hydrostatic Test
Safety Injection Pumps Cold Leg Runout Test
Upper Internals Inspection
As a result of the reactor vessel internals inspection, issues have been
identified concerning IGSCC in control rod guide tube flexures and support
pins (i.e., split pins).
The split pins are utilized to provide attachment
of and lateral support for the guide tubes at the upper core plate.
Each
of the 53 guide tubes contains two split pins for a total of 106 pins.
Split pins have experienced IGSCC and resultant failures in the shank to
collar and/or leaf area. This issue was identified by Westinghouse in the
early 1980's as a domestic industry concern for split pins with certai.n
heat treatments.
In March 1989,
the licensee experienced a split pin
failure (failure location other than those described above, see IR 89-08)
and subsequently shut the plant down to retrieve the loose part from S/G
C. During September 1990, as a result of this failure and recommendations
from Westinghouse, the licensee performed UT on all 106 split pins.
The
results revealed 38 split pins with crack indications; 37 pins had only
shank crack indications, one pin had a leaf crack indication only, and one
of the 37 pins with a shank crack indication also had a leaf crack
indication.
Subsequent to the report period, the licensee conservatively
decided to replace all 106 split pins during the present refueling outage.
This adequately addresses IFI 89-08-02, Review Long Term Resolution Of
Split Pin Cracking Issue. Hence, item 89-08-02 is considered closed.
The control rod guide tube flexure issue, also a previously identified
generic industry problem,
involved cracking and resultant flexure
failures. There are four flexures on each guide tube which contain the
removable inserts on the top end of the upper guide tubes.
The removable
insert provides a flow restriction to minimize bypass flow from the outlet
plenum to the upper head plenum and simultaneously provides guidance for
the drive rod.
As a result of the flexure inspection, the licensee
determined that there were 13 guide tubes which currently require a
flexureless insert (i.e., had one or no sound flexures remaining).
The
flexureless insert was developed by Westinghouse to replace the inserts
previously contained by flexures.
There were 19 guide tubes with two
remaining flexures, the minimum number of flexures needed for insert
restraint. The licensee plans to have a minimum of 34 flexureless inserts
available for installation; however, the licensee is evaluating if,
and
how many, additional flexureless inserts will be installed other than the
required 13.
The results of this evaluation will be documented in
IR 90-23.
No violations or deviations were identified.
8
4. Monthly Maintenance Observation (62703)
The inspectors observed safety-related maintenance activities on systems
and components to ascertain that these activities were conducted in
accordance with TS,
approved procedures, and appropriate industry codes
and standards.
The inspectors determined that these activities did not
violate LCOs and that required redundant components were operable.
In
particular, the inspectors observed/reviewed portions of the following
maintenance activity:
WR/JO 90BCC435
During
the following conditions were
identified: two piston heads had locations where the chromium clading was
burned through; one of the above pistons had the lower oil scraper ring
cracked; and both turbocharger nozzle rings were cracked.
The two lower
pistons had been selected-for inspection based upon their cylinder exhaust
temperatures being at the high end of the acceptance range.
Based upon
the inspection results, two additional lower pistons were removed for
inspections.
These cylinders had also tended to operate at
slightly
higher than average temperatures.
No damage was observed on these piston
heads.
The later two pistons were re-installed and the two damaged
pistons were replaced. The upper pistons in the above mentioned cylinders
were also examined for burn locations; none were observed.
This was
expected,
as the upper pistons operate at lower temperatures than the
lower pistons due to the way fuel is injected into the cylinders.
Both turbochargers were replaced.
The inspectors examined the cracked
nozzle rings.
Each nozzle ring had one crack at approximately the same
location.
The Colt Industries'
technical representative indicated that
this has been a problem on Fairbanks Morse Model 38 TD 8 1/8 engines.
Such cracks are not anticipated to affect the performance of the
turbocharger unless:
(1) another crack would occur and a piece of the
nozzle ring were to break off, or (2) the crack would propagate into the
turbocharger housing.
Neither failure mechanism appeared likely since
there was no evidence of additional cracks and crack propagation into the
housing was not considered feasible as the nozzle ring was bolted to the
housing.
No violations or deviations were identified.
5. Onsite Followup of Events (93702)
On September 11, 1990, at 8:50 a.m., the control room was notified of a
Freon leak/tube rupture in the control room HVAC equipment room which is
located immediately below the main control room.
The shift foreman
directed that the area be evacuated and that control room ventilation be
secured. All personnel who had been in the area were verified to have
exited the area and no injuries occurred.
The freon release lasted for
9
approximately one minute (i.e., the time it
took the HVA unit to
discharge). The area was then secured and preparations for temporary HVAC
equipment room ventilation were initiated. At 9:10 a.m., after review of
the EAL flow chart, the shift foreman declared an unusual event due to a
toxic gas release into the protected area.
Upon hearing the subsequent PA announcement, the inspector went to the
control room. At that time, approximately 9:20 a.m., preparations were in
progress to make the required emergency notifications. At 9:22 a.m., the
emergency communicator notified the State of South Carolina, Darlington
County, Lee County, and Chesterfield County warning points of the UE. At
9:36 a.m.,
the NRC was notified in accordance with 10 CFR 50.72.
At
approximately 9:40 a.m., while reviewing the EAL flow chart, the inspector
questioned the Operations Manager as to the affected area's proper
security classification.
The inspector was informed that based upon a
similar question from an SRO, security was verifying the area's security
classification.
At 9:46 a.m.,
a security supervisor indicated that the
area was not listed in the security plan as a vital area; however, it was
within security doors bounding the auxiliary building and should therefore
be considered a vital area.
Based upon this information,
the SEC
reclassified the event as an Alert (i.e., toxic gas release into a vital
area).
The emergency communicator then notified state and county EOCs of
the reclassification. The TSC was incorporated into the protected area at
10:08 a.m..
At 10:13 a.m., after approximately one-half hour of room
ventilation, initial remote Freon sampling detected 0.5 ppm Freon in the
HVAC equipment room.
At 10:14 a.m.,
the OSC was fully manned and
activated.
At 10:21 a.m.,
the control room was notified that local
sampling results indicated that oxygen levels were 20.8 -
21.0 percent and
Freon levels were 1.9 ppm.
The TLV for Freon is 1000 ppm. Based upon
this information, the SEC terminated the Alert at 10:21 a.m. The TSC had
been fully manned and was prepared to activate when the Alert was
cancelled.
The licensee's review of the event and associated response was documented
in SCR 90-069.
The event was initiated when a worker inadvertently cut a
Freon line to the operating control room heating and air conditioning unit
HVA-2.
The worker had been instructed to cut four empty Freon lines
associated with HVA-1 as part of M-994, Control Room Habitability.
The
worker had made several cuts on two of the lines, was transferred
temporarily to another task, then resumed the Freon line cutting. Prior
to work resumption, another employee pulled one of the cut lines through a
wall penetration. Upon resumption of work, the worker thought he had only
cut one line and continued to cut three more lines.
The fifth line (which
he thought was the fourth) was the HVA-2 charged Freon line that was
adjacent to the HVA-1 empty Freon lines.
The SCR also identified several concerns/weaknesses.
The shift foreman
had to determine whether the gas was toxic and if so, whether or not the
affected area was a protected or vital area. Without adequate procedural
guidance available to define what gases onsite are toxic, he conserva
tively assumed that Freon R-22 was toxic. Additionally, after consulting
10
the security plan, which did not provide a clear definition of the
affected area's status as a vital or protected area, as well as consulting
with other individuals who were also unsure of the area's classification,
he decided that the area was only in the protected area.
As discussed
above, this decision was later determined to be incorrect.
The shift
foreman stated that to his knowledge the equipment in the room was not
considered vital equipment and that much of the equipment in the room was
in the process of being dismantled per modification M-994. Hence, lacking
definitive guidance from the security plan, the shift foreman determined
that the area was not a vital area.
Though this specific event had
minimal safety significance as the total refrigerant quantity released was
small,
it
did highlight a fundamental
weakness in emergency plan
implementation (i.e., guidance and training on EAL flowchart specific
decision blocks have been inadequate).
Previous inspection findings
concerning emergency classification problems are contained in IRs 88-07,
88-16, and 89-27. Specifically, IR 89-27 identified the shift foreman's
failure to recognize the occurrence of an initiating condition for an UE
as an exercise weakness.
Though the drill's artificiality was a major
contributor to this weakness, as discussed in IR 89-27, the identification
of this item as an exercise weakness underscored the concern that
previously identified problems in this area were not completely corrected.
The September 11,
1990 event indicated that proper emergency classifica
tions, especially for non-FSAR Chapter 15 events, continue to be a
weakness.
The failure to correct an exercise weakness identified in IR
89-27 is a violation of 10 CFR 50 Appendix E Section IV.F.5: Failure To
Correct An Exercise Weakness Concerning Event Classification, 90-22-03.
The SCR also discussed the emergency communicator identifying that he did
not correctly dial the automatic ringdown circuit to simultaneously
contact both the state and county warning points and EOCs when the NOUE
was made. The failure to properly notify state and county EOCs of the UE
as required per PEP-171,
step 5.2.1.1 is a violation.
This violation
meets the criteria specified in Section V.G.1 of the NRC Enforcement
Policy for not issuing a Notice of Violation and is not cited.
The
violation is identified as a NCV:
Failure To Implement Procedure PEP 171,
90-22-04.
Additionally, the SCR also identified that manning of the OSC and TSC
occurred without problems. This was significant in that augmentation has
been identified as a weakness in previous emergency exercises.
Specifi
cally, the new beeper notification method for ERO personnel worked well.
Although this cannot be considered a demonstration of the licensee's
augmentation ability during. nights and weekends,
ERO beeper tests
conducted on weekends and in the evening have indicated that both the OSC
and TSC could be activated within procedural guidelines during off-normal
hours.
Two violations, one being non-cited, were identified.
6. Onsite Followup of Written Reports of Nonroutine Events (92700)
(Closed)
LER 89-10,
Inadequate Auxiliary Feedwater Pump Net Positive
Suction Head.
This issue was discussed in IR 89-17, 89-18, 89-20, 89-23,
and 89-32.
Inspector Followup item 89-32-01 was established to review
acceptance test ST-2 for modification M-1018, Auxiliary Feedwater -
NPSH.
The inspectors reviewed the acceptance test performed on December 27,
1989.
The test successfully demonstrated that the modified AFW suction
piping was adequately sized with sufficient NPSH available to allow
simultaneous operation of all three AFW pumps.
(Closed)
LER 89-14,
Loading of Safety-Related Equipment Could Exceed
Assumptions Of Accident Analysis.
This issue was discussed in IR 89-25,
89-31, and 89-32.
The inspectors verified that Agastat digital timing
relays were installed as committed in the LER.
However, the hardware
installation did not completely resolve the concern involving potential
emergency bus overloading during accident load sequencing. Specifically,
under certain grid conditions, sequencing with offsite power available
could result in undesirable emergency buss undervoltages.
This concern
was addressed by the placement of: administrative controls on the VAR
sharing between the coal fired unit (unit-1) and the nuclear unit
(unit-2); restrictions on switchyard capacitor bank usage; and procedural
controls requiring certain loads be in service so they do not have to
sequence onto the their respective emergency buss.
Periodically during
the last cycle, the inspectors verified that these items were being
implemented.
Modification M-1043, Modification of Degraded Grid Voltage
Relay Logic, is scheduled for installation this outage to address this
concern.
(Closed)
LER
90-02,
Reactor Trip During
Performance of Nuclear
Instrumentation Surveillance Test And VIO 90-02-02, Failure To Follow
Procedure OST-007 Resulted In Reactor Trip. In the April 9, 1990 response
to the NOV,
the licensee committed to make changes to OST-007 to help
ensure procedure format will not contribute to personnel error.
Revision
5 to OST-007 was issued on May 7, 1990, with an improved format. A review
of other OSTs identified that similar procedure format weaknesses existed
in OST-001 through OST-006. The inspectors verified that these procedures
were reformatted as committed in a May 10,
1990 supplemental response to
the NOV. Subsequently, OST-009 was similarly formatted in September 1990,
to provide consistent formats among OST procedures.
(Closed) LER 90-05, Failure To Test RPS Logic Channels In Accordance With
Technical Specifications. On May 3, 1990, a telephone conference was held
between Region II
management
and the licensee concerning RPS logic
testing. By letter dated May 11, 1990, the licensee confirmed four verbal
commitments. The inspectors verified that these four items were completed
as committed.
Corrective actions to ensure similar logic testing
deficiencies do not exist will be inspected as part of violation 90-11-01.
No violations or deviations were identified.
12
7. Action on Previous Inspection Findings (92701)
(Open)
URI 89-09-02, Determine If One SI Pump Injection Into Three Cold
Legs Should Be Demonstrated.
On September 25,
1990, SP-938,
Safety
Injection Pumps Cold Leg Runout Test, was performed to measure pump
discharge pressures and flow rates of the A and B SI pumps when each pump
injected into the three cold legs.
The measured cold leg injection header
flow for both pumps was approximately 640 gpm at 360 psig.
Due to these
values being outside the stated acceptance criteria, each pump was secured
prior to the specified two-minute run time data point.
However, the
inspectors observed that both flows and discharge pressures
stabilized
before the pumps were secured.
In accordance with their established
procedure, a 72-hour operability determination period was entered.
The
established acceptance criteria, flow less than 600 gpm and pressure
greater than 500 psig,
had been chosen by engineering based upon
historical anticipated pump performance.
Thus,
failure to meet the
procedural
acceptance criteria did not demonstrate the pumps were
incapable of meeting their intended safety function nor that performance
was degraded.
Initial review indicated that the higher flow rates would
not adversely affect the pump motors; however,
the 1968 Worthington
Corporation estimated NPSH curves did not provide required NPSH values for
flow rates greater than 600 gpm.
Vendor curve extrapolation by the
inspectors indicated that the required NPSH at 640 gpm would be between 33
and 35 ft.
In comparison, a 1988 calculation, FRSS/SS-CPL-1131, showed
with a maximum flow rate of 596 gpm, one SI pump would have 29.8 ft. NPSH
available at the low-low RWST level.
As the NPSH adequacy concern could
not be resolved within 72-hours, the licensee conservatively declared the
SI pumps inoperable and reported the potential problem per 10 CFR 50.72.
At the end of the report period, another SP was being developed to obtain
more accurate flow and pressure data,
as well as additional data which
would characterize the pump and pump motor performance.
(Closed) IFI 89-08-02, Review Long Term Resolution of Split Pin Cracking
Issue.
(See paragraph 3, Upper Internals Inspection.)
No violations or deviations were identified.
8.
Exit Interview (30703)
The inspection scope and findings were summarized on October 18,
1990,
with those persons indicated in paragraph 1. The inspectors described the
areas inspected and discussed in detail the inspection findings listed
below and in the summary. Dissenting comments were not received from the
licensee. Proprietary information is not contained in this report.
Item Number
Description/Reference Paragraph
90-22-01
UNR - Review If TMI Item Commitments
Have
Been Improperly Superseded By
RG-1.97 Commitments (paragraph 2)
13
90-22-02
VIO- Failure To Adequately Implement
Procedures As Required By TS (paragraph
2)
90-22-03
VIO - Failure To Correct An Exercise
Weakness
Concerning
Event
Classification (paragraph 5)
90-22-04
NCV - Failure To Implement Procedure
PEP-171 (paragraph 5)
9. List of Acronyms and Initialisms
CFR
Code of Federal Regulations
CV
Containment Vessel
Diesel Generator
Emergency Action Level
Emergency Operation Center
Emergency Response Organization
EST
Engineering Surveillance Test
ft
Feet
gpm
Gallons Per Minute
HBR
H. B. Robinson
HPES
Human Performance Evaluation System
Heating Ventilation Air Conditioning
IEB
Inspection Enforcement Bulletin
IEN
Inspection Enforcement Notice
Intergranular Stress Corrosion Cracking
IR
Inspection Report
LCO
Limiting Condition for Operation
LER
Liscense Event Report
M
Modification
Maintenance Refueling Procedure
Notification of Unusual Event
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
OEF
Operating Experience Feedback
OMM
Operations Management Manual
Onsite Nuclear Safety
Operations Support Center
OST
Operations Surveillance Test
Preventive Maintenance
Parts Per Million
PNSC
Plant Nuclear Safety Committee
POER
Plant Operating Experience Report
psig
Pounds per square inch -
gage
14
Radiation Monitor
Radiation Monitoring System,
Reactor Operator
Reactor-Turbine Generator Board
Refueling Water Storage Tank
Station Auxiliary Transformer
Significant Condition Report
SEC
Site Emergency Coordinator
Safety Evaluation Report
Spent Fuel Pool
S/G
Safety Injection
Special Procedure
Senior Reactor Operator
TI
Training Instruction
TMM
Technical Support Management Manual
Threshold Limiting Value
TS
Technical Specification
Unusual Event
Unresolved Item
Ultrasonic Testing
VAR
Volts-Amps Reactive
Violation
WD
Waste Disposal
Work Request
WR/JO
Work Request/Job Order