ML20207B261
| ML20207B261 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 10/31/1986 |
| From: | Fredrickson P, Garner L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20207B173 | List: |
| References | |
| 50-324-86-25, 50-325-86-24, NUDOCS 8611110556 | |
| Download: ML20207B261 (26) | |
See also: IR 05000324/1986025
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. . UNITED STATES
- -[pKr?
o NUCLEAR REGULATORY COMMISSION
g" 3 REGION 88
g,
,j 101 MARIETTA STREET.N.W.
'* ATLANTA. GEORGI A 30323
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Report Nos. 50-325/86-24 and 50-324/86-25
Licensee: Carolina Power and Light Company
P. O. Box 1551
Ralei 0h, NC 27602
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Docket Nos. 50-325 and 50-324 License Nos. DPR-71 and DPR-62
Facility Name: Brunswick 1 and 2
Inspection Co October 4, 1986
cte g September 1
Inspectors: W. C -
/0!3/!M
g W. Rulagd
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Cate Signed
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10 3) N
$ L. W. Garner IFate 6igned
Accompanying Per 1: J. R. Patterson eptember 29 - October.3, 1986)
Approved by: \/. f\)
P. E.'Fredrickson, Section Chief
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/d!3//M
Bate'5fgned
DivisionofReactorProjects -
SUMMARY
Scope: This routine safety inspection involved the areas of maintenance obser-
vation, surveillance observation, operational safety verification, Engineered
Safety Features (ESF) System walkdown, onsite Licensee Event Report (LER) review,
in-office LER review, followup on inspector identified and unresolved items, IE
Bulletin followup, sequence of events for Unit 1 scram, TMI action items, Site
Work Force Control Group meetings, internal exposure control and assessment,
plant modifications, and maintenance experience report review,
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Results: One violation - failure to establish an adequate procedure regarding a
diesel generator jacket water cooler service water valve, paragraph 10.
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8611110556 861031
0 ADOCK 05000324
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REPORT DETAILS
1. Licensee Employees Contacted
P. Howe,'Vice President - Brunswick Nuclear Project
C. Dietz, General Manager - Brunswick Nuclear Project
T. Wyllie, Manager - Ergineering and Construction
l G. Oliver, Manager - Site Planning and Control
J. Holder, Manager - Outages
E. Bishop, Manager - Operations
l L. Jones, Director - Quality Assurance (QA)/ Quality Control (QC)
R. Helme, Director - Onsite Nuclear Safety - BSEP
J. Chase, Assistant to General Manager
l J. O'Sullivan, Manager - Maintenance
l G. Cheatham, Manager - Environmental & Radiation Control
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B. Parks, Acting Manager - Technical Support
K. Enzor, Director - Regulatory Compliance
R. Groover, Manager - Project Construction
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A. Hegler, Superintendent - Operations
J. Wilcox, Principal Engineer - Operations
W. Hogle, Engineering Supervisor
ineering Supervisor
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B. Wilson,I&C
R. Creech, Eng/ Electrical Maintenance Supervisor (Unit 2)
l R. Warden, I&C/ Electrical Maintenance Supervisor (Unit 1)
i W. Dorman, Supervisor - QA
l W. Hatcher, Supervisor - Security
- R. Kitchen, Mechanical Maintenance. Supervisor (Unit 2)
! C. Treubel, Mechanical Maintenance Supervisor (Unit 1)
l R. Poulk, Senior NRC Regulatory Specialist
D. Novotny, Senior Regulatory Specialist
W. Murray, Senior Engineer - Nuclear Licensing Unit
Other licensee employees contacted included construction craftsmen,
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engineers, technicians, operators, office personnel, and security force
members.
2. Exit Interview (30703)
The inspection scope and findings were summarized on October 7,1986,
with the general manager. The violation, failure to establish an adequate
were
procedure
discussed(paragraph
in detall. 10),
Theand an unresolved
licensee Item (paragra)h
acknowledged the findings10)ithout
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exception. The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during the inspection.
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3. Followup on Previous Enforcement Matters (92702)
Not inspected.
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4. Maintenance Observation (62703)
The inspectors observed maintenance activities and reviewed records to
verify that work was conducted in accordance with approved procedures,
Technical Specifications (TS), and applicable industry codes and standards.
The inspectors also verified that: redundant components were operable;
administrative controls were followed; tagouts were adequate; personnel
were qualified; correct replacement parts were used; radiological controls
were proper; fire protection was adequate; quality control hold points were
adequate and observed; adequate post maintenance testing was performed; and
independent verification requirements were implemented. The inspectors
independently verified that selected equipment was properly returned to
service.
Outstanding work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance.
The inspectors observed / reviewed portions of the. following maintenance
activities:
MI-03-1BX14 821-PT-N023A, B, C, & D Rosemount Gauge Pressure Trans-
mitter.
MI-10-511A Mechanical Inspection and Lubrication of Limitorque
Operators Installed in Q-List Equipment - Unit 1.
MI-10-511B Mechanical Inspection and Lubrication of Limitorque
Operators Installed in Q-List Equipment - Unit 2.
86-AJUU1 Replace Printed Circuit Board on 23A-2 Battery Charger.
86-BHUB1 No. 2 Fuel Oil Tank Level Switch Repair.
86-BLZJ1 Maintenance on LPRM 44-37-B.
86-BMJN2 High Pressure Coolant Injection (HPCI) F008 Valve Spring
, Pack Inspection.
86-BNAG1 2C Conventional Service Water Pump Motor Oil Cooler
Repair.
86-BNEG1 Unit 2 Main Steam Line Radiation Monitor D Repair.
86-BNJJ1 Unit 1 HPCI Steam Line Outboard Isolation Valve, F003,
Yoke Clamp Stud Replacement.
No violations or deviations were identified.
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5. Surveillance Observation (61726)
The ~ inspectors observed surveillance testing required by Technical Specifi-
cations. Through . observation and record review, the inspectors verified
that: . tests conformed to TS requirements; administrative controls were
followed; personnel were qualified; instrumentation was calibrated; and data
was accurate and complete. The inspectors independently. verified selected
test results and proper return to service of equipment.
The inspectors witnessed / reviewed portions of the'following' test activities:
1MST-APRM23Q Average Power Range Monitor (APRM) C Channel Calibration /
Functional Test.
2MST-HPCI27M HPCI and Reactor' Core Isolation Cooling (RCIC) Condensate
Storage Tank (CST) Low Water Level Instrument Channel,
Calibration.
01-3.1 Periodic Testing and Control 0perator Daily Surveillance
Report - Unit 1.
01-3.2 Periodic Testing and Control Operator Daily Surveillance
Report - Unit 2.
PT-15.6 Standby Gas Treatment System Operability (Unit 1).
During performance of 2MST-HPCI27M, a monthly procedure, the ' inspector
observed that step 7.2.25 was misinterpreted. The step states, "Close drain
valve on the E41-LSL-N002 and E51-LSL-4464 Instrument Drain Valve, CO-V151."
The individual closed C0-V151 instead of closing the drain valve on C0-V151.
The drain valve on C0-V151 has no number. Closure of the wrong valve
isolated the level device. When the subsequent steps were performed to
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determine the reset of the switches, the-reset value could not be determined.
The ~ technicians re-aligned the valves and completed the reset check satis-
factorily. The item was discussed with the appropriate crew supervisor.
The licensee plans to clarify the procedure step and evaluate the'desira-
bility of numbering and tagging the subject valve.
No violations or deviations were identified.
6. Operational Safety Verification (71707)
The inspectors verified conformance with regulatory requirements by direct
observations of activities, facility tours, discussions with personnel,
reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR
50.54 and the TS were met. Control room, shift supervisor, clearance and
jumper / bypass logs were reviewed to obtain information concerning operating
trends and out of service safety systems to ensure that there were no
conflicts with TS Limiting Conditions for Operations (LCO). Direct obser-
vations were conducted of control room panels, instrumentation and recorder
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traces important to safety to verify operability and that parameters were
within TS limits. The inspectors observed shift turnovers to verify that
continuity of system status was maintained. The inspectors verified the
status of selected control room annunciators.
Operability of a selected ESF train was verified by insuring that: each
accessible valve in the flow path was in its correct position; each power
supply and breaker, including control room fuses, were aligned for components
that must activate upon initiation signal; removal of power from those ESF
motor-operated valves, so identified by TS, was completed; there was no
leakage of major components; there was proper lubrication and cooling water .
available;'and a condition did not exist which might prevent fulfillment of
the system s functional requirements. Accessible instrumentation essential
to system actuation or performance was verified operable by observing
on-scale indication and proper instrument valve lineup.
The inspectors verified that the licensee's health physics policies /proce-
dures were followed. This included a review of area surveys, posting, and
instrument calibration.
The inspectors verified that: the security organization was properly manned
and security personnel were capable of performing their assigned functions;
persons and packages were checked prior to entry into the protected area
(PA); vehicles were properly authorized, searched and escorted within the
PA; persons within the PA displayed photo identification badges; personnel
in vital areas were authorized; and effective compensatory measures were
employed when required.
The inspectors also observed plant housekeeping controls, verified position
of certain containment isolation valves, and verified the operability of
onsite and offsite emergency power sources.
- a. Items Noted During Walkdown
O'n September 14, 1986, the inspector observed no position indication
for the "F" Drywell to Suppression Chamber Vacuum Breaker. The licensee
immediately investigated and found that the close indication light bulb
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was burned out. The bulb was replaced and the position indication
returned to service.
On September 23, 1986, the inspector observed that the Unit 1 Local
Power Range Monitor (LPRM) detector at position 04-29 level D, showed a
downscale indication. Because the reactor had reached approximately
90% of full power after a scram recovery, this appeared abnormal. The
licensee investigated the indication and determined that the LPRM was
inputing into APRM B correctly and hence, the requirement to have 2
operable detectors at each level (T.S. Table 3.3.1-1, note c), was
being met. The detector showed an output of 27 watts /cm2. The set-
point for the downscale indication is 5 watts /cmi. The licensee
initiated a trouble ticket to correct the downscale indicator circuit.
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On September 26, 1986, theinspectorobservedthaN?-SW-PI-2871,the
2C conventional service water pun 9 lube water supply: pressure indicator,
was reading zero. This might .inoicate a lack of lube water to the 2C
conventional service water pump motor upper seal oil cooler. The
supply- and return lines to the c'ooler also felt abnormally warm,
indicating low or no flow to the cooles BecatGe of the pumps
particular piping configuration, it is difficult to determine if flow
is discharging from the return line. This condition was reported to
the licensee who verified the condition, shut the pump down, and
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initiated a work request, 86-BNAG1, ^to correct tJe problem. The
pressure regulating valve contained illt. The cyclorae separator was-
cleaned and the lines were flushed before the pump was returned to
service. .
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On October 2,1986, a followup inspection of the labe water supply to
the 2C conventional service water pump retealed that relief valve,
2-SW-RV11, was partially diverting flow fros the motor cooler. The
valve, located between the pressure reducing valve and the motor
cooler, was not seated at an indicated prerisure of,16 psig. The normal
setpoint is 25 plus or minus 2.5 psig; sThe licensee issued work
request 86-BNXAl to correct ths problem. .The inspector also observed
that the conduit to the 2C converttional sirvice water pump strainer
motor is rusted at the floor level such that the conduit is partially
broken and is bent to one side. The_. licensee has issued work request
86-BNWY1 to evaluate the condition,
b. Unit 1 Residual Heat Removal (RHN) Room Coolir -
The licensee isolated the service water to the Unit' 1 south (A) RHR
room cooler due to a one-half gallon per minute leak. The north (B)
RHR room cooler was functional. The inspector noted the cooler was
isolated during a routine inspection on September 25, 1986.
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The coolers are redundant, each ~ capable of cooling the RHR, RCIC and
HPCI areas. The coolers are parteof the reactor. building emergency
cooling system, described in FSAR Section 9.4.3. The coolers are
designed to keep the Emergency Core Cooling System (ECCS) areas at or
below 148 degrees F during an emergency pumping situation. The coolers
are thermostatically operated. During normal operation, the A cooler
will start if temperature reaches 120 degrees F and an alarm will go
- off in the control room. At 145 degrees F, the B room cooler will
start, but no alarm will sound. /
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The licensee had isolated the service water tq the A RHR room cooler on
September 24, 1986, and had taken a tracking 1.C0 'o bt on the equipment.
A tracking LCO helps the lic~ensee to keep track of TS equipment that is
out of service. No ACTION statement has yet been entered.
The inspector questioned the operability of the affected ECCS systems
because a single failure with one cooler out could totally disable
cooling to those ECCS systems. The license.e stated that no LC0 existed
because:
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o analysis shows that room coolers are not needed during the first
10 minutes of an accident.
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o After 10 minutes, the licensee can take credit for operator action.
o Annunciators and their associated procedures would direct the
operator to send an auxiliary operator to unisolate the A RHR
room. cooler if neeoed.
The inspector plans to - review further the licensee's operation of the
RHR room coolers with one cooler isolated. This is an Inspector
Followup Item: Review RHR Room Cooler Operation (325/86-24-05).
No violations or deviations were identified.
7. Engineered Safety Features System Walkdown (71710)
The inspectors performed a walkdown of the accessible portions of the
Units 1 and 2 RHR. systems to verify system operability. The walkdown i
included the accessi'ile portions of the LW Pre <.sure Coolant Injection 's
-(LPCI) mode, the shutdown cooling mode, the suppression pool cooling mode, s s
the suppression pool spray piping, the minimum flow and test return lines to
the suppression pool, and containment spray piping. Neither the head spray
lines . nor the f"el pool cooling to the RHR system cross-connect lines were '
included. The inspectors verified that: hangers and supports were func-
tional, valves and pumps were properly maintained, component labeling was
correct, instrumentation was properly installed and functioning, valves
were in the correct position, power was available to motor-operated valves,
and the Division I and Division II cross-tie valves (F010) were closed with
power removed as per TS 4.5.3.2.a.3.
The inspector verified that the system check lists in OP-17, Residual Heat I
Removal System Operating Procedure, Revision 10 for Unit 1 and Revision 66 -
for Unit 2, contained the major system valves as indicated by the RHR piping
and instrumentation drawings, D-25025 Sh. lA (Rev. 29), D-25025 Sh.1B g
(Rev. 27), D-25026 Sh. 2A (Rev. 33), D-25026 Sh. 2B (Rev. 31), D-2525 Sh. lA
(Rev. 31), D-2525 Sh. IB (Rev. 29), D-2526 Sh. 2A (Rev. 31), and D-2526
Sh. 2B (Rev. 32). ,
The following items were identified: iI -
On September 8, 1986, the inspector and a member of the licensee's [
engineering staff observed that the stem protector for 1-E11-F028B was ,
missing. The valve is the Unit 1, Division II Suppression Pool Discharge
Isolation valve. The valve was last inspected on July 20, 1986, per MI-10-
511A, Mechanical Inspection and Lubrication of Limitorque Operators Installed
'in Q-List Equipment - Unit 1 Reactor. Step 3 of this procedure requires'the
removal of the stem protector to allow inspection of the stem. Step 4
requires replacement of the stem protector. The procedure completed in i
July 1986 makes no reference to a missing stem protector. The licensee has
verified that no authorized work has been performed on the valve since that 4
time. The only outstanding work request on the valve is one which specifies ,,
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L that the valve needs to be repacked. The Unit 1 mechanical supervisor indi-
. cated. that the work crew who last performed MI-10-511A vaguely remember
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finding a valve in the general area without a stem protector;, however,
they thought.a work request had been issued to correct the problem. None
I can beifound. The licensee installed a stem protector on E11-F028B on
- - September 10, 1986, per work request 86-BKWU1.
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t On ' September 29, 1986, the ' inspectors observed that the stem protector
- extension for 2-E11-F0478 was unthreaded and laying against the stem.
This valve is the Unit 2, Division II RHR heat exchanger inlet valve.
The 2-E11-F004D valve was found with duct tape over the top of the stem
protector :instead of. a metal _ cap. In' addition, on September 10, 1986, the
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licensee found 1-E11-F075, the RHR service water inboard injection valve,
with no stem protector installed. MI-10-511A had also been performed on
i 1-E11-F075 during 1986. The licensee issued work requests to correct the
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' deficiencies. The last performance of the similar maintenance instruction
on' Unit 2 for 2-E11-F047B and 2-E11-F0040 was not examined by the inspector.
!. The licensee has also performed inspections of other accessible Unit-1
valves and,found no additional missing stem protectors. A similar inspection-
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is planned for Unit 2. The licensee stated that in 1984, stem protectors
were repla'ced on both 1-E11-F028B and 1-E11-F075 (work request- 1-M-84-4729).
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All the above mentioned valves are' considered Environmentally Qualified
N (EQ). Failure ,to, have the stem protectors properly installed does not
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render the valves inoperable or violate the EQ status.of the valve actuators.
The Limit'orque Corporation BWR Qualification Report Addendum A, No. 600376A,
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dated January 1979, states in Section 3.3, paragraph D, that,.
...,(ttihy). designed the actuator with the philosophy that the environmental
- s ambient conditions be permitted to enter the actuator with minimal restric-
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tions,' thus insuring a reliable unit that _has .the capability of performing i
its function during an accident." Hence, the missing stem protectors do not
, effect the EQ status of the valves. A non-conformance report, NCR S-86-045,
was issued on October 2,-1986,- concerning stem protectors.
o The inspector observed on both units that "U" bolts and/or "U" bolt nuts
, were missing from the RHR discharge header relief valves, F025A and B,
discharge lines. The licensee wrote a work request to correct the problem.
j Two snubbers; 1-E11-113SS157 and 2-E11-113SS410, showed early signs of
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corrosion on the shafts. Work request 86-BNLE1 and 86-BNRB1 were' issued to
evaluate their condition. The licensee has contacted the vendor to see if
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some protective coating can be applied to prevent corrosion and/or pitting
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of the shafts.
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The following items on other systems were observed and reported to the
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o Unit 1 structural support steel for mark No.1-E51-42SS78 appeared to
have only a tack weld. This is not-in accordance with design. drawing-
9527-F-12025. The licensee considers the support o
issued a site memorandum, BPE-4918, to resolve theas'perable but- has
constructed"
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with the design drawing. .
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o Unit 1 RCIC barometer condenser condensate pump discharge .line sway
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. support between the- E51-F004 ~ and E51-F005 valves was -missing a cotter
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. pin. Work request 86-BKMH1 issued to correct. ;
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o. ~ Unit 1:RCIC steam line temperature sensor junction box'Q17 had water
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standing on it as a result of condensation of a-nearby steam leak.
' Work request 86-BKMS1 issued to correct steam-leak.
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o ' Unit-1 RCIC snubber 1-E51-42SS75 had low fluid indication. Licensee
refilled snubber.
o Unit 1 HPCI outboard steam line. isolation valve,1-E41-F003, was
observed on September 30, 1986, to have. nuts on both sides of two studs
not fully engaged. This represents 2 out of the 4 studs on the yoke
clamp.- The yoke-clamp holds the yoke and actuator assemblies to the !
- bonnet. The licensee installed longer studs on October 1,1986, .in
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accordance' with work request 86-BNJJ1. Review of records indicates '
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that the valve was last re-assembled on May.23, 1983, per work request
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' 1-M-82-3197. The valve is located 'in a high radiation area. The
licensee reported that the blanket Unit 1 walkdowns had not yet covered
this valve or other valves.
o Unit'2 HPCI suppression pool high level switch 2-E41-LSH-N015A (used to
transfer' suction from condensate storage tank on high level), was found
to have the' adjacent "U" bolt missing on one instrument leg and the
adjacent "U" bolt nuts loose on the other instrument' leg.
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o The housekeeping was generally good.. However, additional attention was
r needed in less accessible. areas. Trash such as pieces of paper, cloth
gloves, rollt ef duct tape, etc. , were seen in cable trays and laying
i on valves _ ano other components on the HPCI roof.
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- The ' inspectors believe that the above-mentioned items, especially .the HPCI
- : steam valve, the stem protectors, and the 2C conventional service water
motor cooler (see paragraph 6), underscores a continuing weakness .on the
licensee's part to identify and/or maintain equipment in the designed
configuration. A similar problem was identified as a violation in inspec-
tion' report No. 325,324/86-01, paragraph 6. The inspectors have been
- informed that in response to report No. 325,324/86-01 and.their own manage -
ment ' initiatives, more than 700 work requests have been initiated and
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completed to address items in this --area of concern. The inspectors have
- determined through review of outstanding work requests that the effort is
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ongoing. Additional management attention is needed to further increase
plant staff awareness of plant components and their condition. Because of
the ongoing efforts in this area with regard to corrective action for the :
previously discussed violation, no Notice of Violation is being issued; but
management needs to reemphasize corrective action in this area to avoid
potential future enforcement action.
No violations or deviations were identified.
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b 8. Onsite Review of Licensee Event Reports (92700) ,
l The listed LERs were reviewed to verify that the information provided met
NRC reporting requirements. The verification included adequacy of event
description and' corrective action taken or planned, existence of potential
- generic problems and the relative safety significance of the event. Onsite
' inspections were performed and concluded that necessary corrective ~ actions
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have been taken in accordance with existing requirements, licensee conditions :
and commitments.
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(CLOSED) LER 1-85-55, Auto Starting of Emergency Diesel Generators and
4 Primary Containment Groups. 2, 3, 6, and 8 Isolations Resulting from Loss
of Emergency Electrical Buses E-1 and 10. While the plant was in mode 5,
! an inadvertent short occurred during connection of a voltmeter. This
resulted in a . trip of unit electrical bus ID. The unit's emergency AC
diesel generators (DG) started and DG No.1 tied on.to E-1 to re-energize
i. the bus. Other equipment isolations and initiations occurred ~as expected.
The subject. plant modification acceptance work procedure was revised to
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change the physical method of- making electrical connections. This should
preclude inadvertent shorting between adjacent terminals.
-(CLOSED) LER 2-83-08, CST Level Low Instrument Calibration Problem - Vent
Partially Blocked. Maintenance has performed 4 annual inspections which
- found no evidence of organic-deposits or residue. In 1986, the licensee
decided further annual inspections were' not necessary. A Task Action
Request, TAR 883-221, has been issued by engineering to modify the vent line-
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but the project has not been funded. As an interim measure, the licensee
has made a permanent change to MST-HPCI27M, HPCI and RCIC CST Low Water
Level Instrument Channel Calibration, to blow compressed air through the
vent. This is performed monthly. This has proven sufficient' to prevent
recurrence of the problem. LER 2-83-51 also involved a similar e~ vent.
j (CLOSED) .LER 2-83-25, Drywell to Suppression Pool Vacuum Breaker ' Closed
{ Indicator Failed. The inspector reviewed completed work request 2E-83-588,
! which repaired the subject switch. The inspector has no further questions
at this time.
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(CLOSED) LER. 2-83-29, Missing Latch and Out of Adjustment Seal on Reactor
Building Airlock. The items were repaired by work requests 2M-83-534, 555,
578 and 717. The inspector verified that the doors are included in the
periodic inspection procedure MI-10-5238, Swinging Door Inspection - Reactor
No.-2, Revision 1, dated October 27, 1982.
'(OPEN)- LER 2-83-33, Main Steam Line Radiation Monitors A and D Out 'of
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Calibration. The subject monitors were re-calibrated. The licensee
!- reported that an outdated section of the calibration procedure was used for
calibration of the D channel. The licensee modified their administrative
L controls concerning. permanent changes when initiated by temporary revisions.
The inspector reviewed the applicable Administrative Procedure, section 5.5,
and has no further questions at this time. Because of noise from other
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' instrumentation during calibration-and recurring drift problems with the
existing instrumentation, the-licensee is evaluating installation. of new
monitor drawers. These new electronic packages (GE NUMAC), are on site.
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Installation of these drawers will first be on the Steam Jet Air Ejector
'(SJAE) radiation monitors. Installation in the main steam line radiation
monitor circuit will proceed if the equipment performs well in the SJAE
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, service. This item will remain open pending evaluation and' installation
of the new equipment.
(CLOSED) LER 2-83-50, Remote Shutdown Re'sidual Heat Removal System Flow and
Head Spray Flow Indicator Instrument Inadvertently Isolated. The event was
attributed to personnel error. The licensee committed to have appropr1 ate
plant operations personnel review the LER. The inspector verified via the
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training roster. and the certification forms that the subject review was
completed by the. majority of licensed operators.
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(CLOSED) LER 2-83-51,. CST Level Low Instrument Did Not Respond to Test
Input Due to Vent Line Blockage. This is a-similar item to that-reported
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in LER 2-83-08. See LER 2-83-08 write-up in this report.
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! (CLOSED) -LER 2-83-53, Main Steam Line Radiation Monitor D Out of Calibra-
tion. This is similar to LER 2-83-33. See write-up on LER 2-83-33 in this
,
report. This item is-being closed for administrative purposes.
I (CLOSED) LER 2-83-56, Control Rod 26-19 Does Not Have Position Indication
for Several ~ Notches. The problem was corrected in June 1984, by repair of
a bent pin in the position indicator probe connector.
(CLOSED) LER 2-86-20, Reference Leg Perturbation Initiate Reactor Scram.
This item is-discussed in paragraph 17 of this report.
No violations or deviations were identified. l
9. In Office Licensee Event Report Review (90712)
The listed LERs were reviewed to verify that the information provided met
, NRC reporting requirements. The verification included adequacy, of event
description and- corrective action taken or planned, existence ~of potential
,
' generic problems and the relative safety significance of the event.
(CLOSED) LER 1-85-23, Primary Containment Group 8 Isolation of Reactor
Shutdown Cooling. While the unit was in a refueling outage with the reactor
cavity flooded and the fuel po~ol gates removed, the residual heat removal
,
system shutdown cooling inboard valve,1-E11-F009, shut. This event was
attributed to a spurious interruption of the logic circuitry to the reactor
steam dome pressure instrument, 1-B32-PS-N018A-1. A possible cause was
' ongoing work activities in the vicinity of the associated centrol room
~
residual heat removal isolation actuation relays. Possible correlation
could not be determined. The instrument actuation setpoint was checked and
found within required tolerances.
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(CLOSED) LER 1-85-52, Primary Containment Group 6 Isolation During
Investigation of Alarm Annunciation. A bad solder joint connection caused
the event. The connection was repaired and the radiation monitor returned
to service within two hours.
No violations or deviations were identified.
10. Followup on Inspector Identified and Unresolved Items (92701)
(CLOSED) Inspector Followup Item (325/83-26-03 and 324/83-26-03), Refurbish
Fire Pump Diesel Fuel Line Solenoid Valve. The licensee performed an
analysis which demonatrated that the subject valve setpoint could not be set
such that the intended function could be met. The valve was installed to
isolate the line if a break-should occur to prevent a fire from damaging the.
nearby electric driven fire pump. The licensee submitted on September 19,
1985, a request for relief from this commitment. On September 17, 1986, a
letter from E. Sylvester to E. Utley granted _the relief based upon other-
measures taken by the licensee. The subject valve has been removed.
(CLOSED) Unresolved. Item (324/86-22-02), Diesel Generator No. 4 Jacket
Water Cooler Service Water Outlet Valve Not Full Open. The inspector had
found the above not fully open during a plant tour on August 26, 1986.
An auxiliary operator had partially closed the DG No. 4 jacket water cooler
service water outlet valve (SW-V209) to clear a local low service water
pressure alarm. OP-39, Diesel Generator Operating Procedure, Rev. 28,
June 25, 1986, Section 8.1, addresses adjusting lube oil and jacket water
temperatures. The procedure does not require the operator to manipulate
the jacket water cooler service water outlet valves. OP-39, Section 8.1,
addresses adjustments of the temperature control bypass valves, the jacket
water cooler outlet automatic Temperature Control. Valves (TCV), and the lube
oil TCVs. No other procedure addressed how jacket water cooler service
water outlet valves should be adjusted when changing jacket water pressure
for the DGs.
The operator had adjusted V209 and two other DG jacket water cooler service
water outlet valves on August 23, 1986, in response to a local low service
water pressure alarm. The annunciator procedure, APP-DG-LP, Annunciator
Procedure for Diesel Generator Local Panels, Rev. 0,. April 24,1986, alarm
3-8, low service water pressure does not require the operator to adjust
V209.
Once the operator manipulated the jacket water cooler service water outlet
valve with no governing procedure, there were no administrative controls in
place to have the valve position independently verified in accordance with
the requirements of TMI action item I.C.6.
The inspectors concluded that prccedures were inadequate in that no proce-
dure . adequately controlled the manipulation of the DG jacket water cooler
service water outlet valves during operation of the engine. This is a
Violation: Inadequate Procedure to Control DG Jacket Water Cooler Service
Water Outlet Valves (324/86-25-01).
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- The; licensee had o'perated the DGs in the past with the cooler outlet valves
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partially. shut. LThe licensee decided to leave the valve normally full open.
The license.has concluded that neither valve position would adversely affect
diesel generator operability. .The inspector will re-examine this ' area to
-verify the '. licensee's conclusions. This is an Unresolved Item: Diesel ,
r
Generator Jacket _ Water Cooler Service Water Outlet Valve - Required Position
[ (325/86-24-02 and 324/86-25-02).
One' violation and one unresolved item were. identified.
11. IE. Bulletin Followup (92703)
(CLOSED) IEB 78-09, BWR Drywell Leakage Paths Associated With Inadequate -
.
Drywell Closures, 325/78-BU-09' and 324/78-BU-09. The inspector verified
[ that the licensee maintains and uses procedures ~that control the removal and
installation of drywell closures. The licensee,- in MP-08, Shield Block and.
Reactor Drywell Head Installation and Removal, Rev'.16,. specifies the
torquing sequence and verifies that no galling. has occurred by counting
flats on head bolts.
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The inspector verified that the licansee had adequate procedures in place to
rein ~ stall: other bolted. containment closures. The inspector reviewed the
following procedures:
-MP-08 Shield Block and Reactor- Drywell Head Installation and
JRemoval,;Rev. 16
MI-16-562- Torus Hatch Cover (Removal and Instal.lation), Rev. 5.
,
.MI-16-563 CRD Hatch Cover (Removal and Installation), Rev. 3.
j- MI-16-595 Installation of the nrywell Equipment Hatch Cover, Rev. 1.
MI-16-596 Installation of the Drywell Equipment / Personnel Hatch Cover,
, Rev. 1. _
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MI-16-601 Installation of Drywell Top Head Manway Cover, Rev. 1.
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' The inspector verified that MI-16-563 was used to're-install .the CR0 hatch
'
cover. The inspector reviewed PT-20.3.3, CRD . Hatch Local Leak Rate Test
(LLRT) for~ Containment Isolation, Rev. O,- performed on Unit 2 on June 23,
1986, and on Unit 1 on November 16, 1985. The PT results~show that the CR0
,
hatch had been adequately re-installed.
12.~ Sequence of Events for Unit 1 Scram on September 13,,1986 (93702)
I The inspectors reviewed the post-scram review packa'ge and other documents, i
-interviewed plant personnel, and reviewed the diesel generator starting
logic. with electrical system engineers. The inspectors provided a sequence
,
of events to NRR,'IE, and RII to aid NRC review concerning.the event. The
inspectors' Sequence of Events (SOE) was based on information provided by
e
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the licen3ee with selected information verified by the inspectors. The SOE
that follows is substantially the same information verified correct by the
licensee in a special meeting on September 17, 1986.
Unit 1 was at 100% power and had been operating for 19 continuous days.
Initial cycle 5 startup was on October 30,'1985. Refueling outage scheduled
to start January 31, 1987. No.other evolutions in progress at the time of
the scram.
Time Event Comment
'
10:54 a.m. Shifted main generator Automatic voltage regulator
<
voltage regulator (VR) had been erratic. Planned
to manual to clean auto controls.
10:55 a.m. Switchyard voltage begins Later found a bad motor-
to swing (about 10 KV). operated manual potentiometer -
wear products matter found on
wiper to potentiometer face.
Operator attempts to
transfer VR back to auto.
Prior to
10:58:57 a.m. 4160 V buses El and E2 All 6 degraded voltage
(ESF Buses) trip on devices trip. 3727 V plus
degraded voltage as or minus 9 V with a 10 plus
designed. Diesel or minus .5 sec. delay (see.
Generators (D/Gs) 1 and T.S. 3.3.3.5).
2 receive a start signal.
Main steam temperature Deenergization caused by
sensor relays deenergize, loss of power source of El
causing a group 1 and E2 (ESF Buses) trip
isolation (Main Steam' relays.
Isolation Valve (MSIV)
closure).
10:58:57 a.m. MSIVs 90% open scram. All 4 channels.
10:58:57+a.m. High Pressure Coolant 187" is normal operating
Injection (HPCI) and level. MSIV closure caused
Reactor Core Isolation level' shrink and pressure
Cooling (RCIC) start rise. LL2 signal only
when Low Level 2 (LL2) momentary. HPCI did not
reached (118"). inject since LL2 was reset.
F006,HPCIinjectionvalve,
was ready to open if needed.
RCIC was available but did
notinject.
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Time Event Comment
[C55tinued)
10:59:06 a.m. Reactor Protection System The power sources of El and
Motor Generator (RPS MG) E2 Buses lost power when the
sets A and B trip. '
undervoltage relays tripped.
(Refer to FSAR Figure
8.3.1-1.)
About
10:59:07 a.m. D/Gs 1 and 2 pick up El
and E2 (ESF Buses
powered from Unit 1).
10:59:12 a.m. Safety Relief Valves A, C - 1105 setpoint
(SRVs) A, C, D, E, D, E - 1115 setpoint
and L automatically L - 1125 setpoint
open (of 11 SRVs) as Licensee estimates pressure
indicated by tailpipe reached 1120 plus or minus 7
temperatures. Initial psig: thus valves that did
50.72' report indicates not lift are within plus or
8 of 11 tailpipe .
minu~s 1% of setpoint. The A
temperatures did not sonic detector had slow
elevated and all sonic response time. The A sonic
indicators memory lights module was' replaced and
were lit. 5 relief valves tested satisfactory. Only
actually responded as tail pipe temperature showed
indicated by tailpipe that L lifted. L sonic
temperatures. The found bad during startup 250
sonic indicator psig test. (T.S. 3.0.4
indications were caused N/A.) License will repair
by short-term loss of detector.
power to the detectors.
10:59:33 a.m. Diesel Generators 3 and Start on Unit 1 main
4 start. generator primary lockout.
11:00 a.m. HPCI and RCIC tripped on As operator attempts to
high level, 208 inches, inject HPCI in response to
when HPCI F006 valve, vessel level decrease due
injection valve, was to SRV lifts.
opened by the operator.
11:01 a.m. Operator started to open E0Ps require operator to
SRVs A, E, J, B, F & D maintain pressure at S950
as necessary. psig using SRVs. (To
distribute heat load in
torus.)
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Time Event Comment
TCo5tinued)
Prior to *
11:06 a.m. HPCI oscillations occur HPCI system was in automatic
during manual restart. and being placed in the
Condensate Storage Tank
(CST) recirculation mode.
Oscillations stopped when
HPCI placed in manual.
Oscillations caused by
inadequate procedural
guidance.
11:06 a.m. HPCI tripped on high level. hen the injection valve was
open, HPCI quickly fed the
vessel, tripping on high
level.
11:10 a.m. RPS "A" MG set on. RPS "B" Output breaker of "B" MG
on alternate power supply. stuck in tripped condition.
This is not an Emergency
Protective Assembly (EPA)
breaker. Breaker repaired.
11:28 a.m. Intermediate Range Monitor IRM F in range 1. Licensee
(IRM) F spike, gives half troubleshooting, found cable
scram. and connector problems on
9/15. Cleaned connections
and performed Performance
Tests. Started unit with
IRM F in bypass.
11:34 a.m. SRV Lifts terminated.
11:37 a.m. RCIC injecting and HPCI in HPCI used for pressure
CST recirculation mode. control.
11:40 a.m. HPCI injected for about See 11:06 a.m. entry.
1 minute, oscillations
occurred but HPCI did
not trip.
11:43 a.m. MSIVs reopened. Re-established condenser
as heat sink.
standby.
11: 51 a.m. One feed pump in service Licensee using feed system
for level control.
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Time Event Comment
[Coiitinued)
12:13 p.m. D/Gs 3 and 4 placed in
standby.
12:30 p.m. Average Power Range 2 Low Power Range Monitors
Monitor (APRM) F (LPRMs) failed,
noticed upscale. 44-21-A read 20 watts
12-21-A read 40 watts
with power in source-range.
After routine trouble-
shooting, licensee installed
pre-approved plant mod to
re-assign 2 LPRMs from
LPRM group A to_APRM F.
Failure cause unknown.
APRM F left in bypass during
unit restart until modification
acceptance test
completed.
Main' steam line rad Detector had been losing
monitor B_ failed down- sensitivity but was still'
scale. passing weekly
surveillance. Replaced
detector.
1:19 p.m. 50.72 phone call.to NRC. Resident Inspector informed
by licensee.
1:37 p.m. Re-energized El and E2 from El and E2 re-energization
1D and 1C, respectively. delayed while investigation
Placed D/G 1 and 2 in was completed.
standby.
1:58 p.m. South Residual Heat Sump pumps in RCIC area had
Removal (RHR) room been in pull to lock due
(RCIC area) high sump to clean up of service
level alarm. (salt) water leak on 9/11.
Licensee investigating
source of leak.
2:00+ p.m. RCIC suction pressure low Licensee looks for leak.
low alarm. High point vent shows
system is full.
RCIC CST suction valve RCIC suction relief valve
shut. stuck open. Corrosion
prevented reseating of
valve.
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Time Event Comment
{Uohtinued)
6:00 p.m. RCIC declared inoperable SR0 concerns that RCIC
when keepfill vent piping was partially
showed system not drained due to relief valve
completely filled. leak. Valve later repaired.
8:00 p.m. Backup Nitrogen (N2) Valve 1-RNA-PCV-5247 had
low pressure alarm. damaged 0-ring and
scratched valve seating
surfaces.
4
9/15
4:30 p.m. Conference call between
Region II and CP&L.
9/16
1:43 a.m. Reactor Critical. HPCI tested satisfactory at
165 psig. Further testing
to be done at 1000 psig.
Based on the SOE and additional inspections, several issues arose.
4 a. RCIC Pump Suction Relief Valve
The RCIC pump suction Relief Valve (RV) was found stuck open due to
corrosion buildup. The licensee identified six Unit 1 RVs and five
Unit 2 RVs on ECCS systems which are manufactured by Lonegren and are
~
in similar applications (ECCS pump suction lines). The valves are:
1-E11-F029,1-E11-F030A, B, C' & D,1-E41-F020, 2-E11-F029, 2-E21-F032A
& B, 2-E41-F020 and 2-E51-F017. The licensee plans to remove these
valves during subsequent scheduled system outages and perform functional
testings of the valves using their normal ISI procedure. Based upon
the test program, the licensee will evaluate if any further action is
warranted. ' This is an Inspector Followup Item: Review of Lonegren RV
Test Program (325/86-24-03 and 324/86-25-03).
b. 10 CFR 50.72 Report
The inspector listened to a tape recording of the 50.72 report with
the acting Operations Manager and the Director of Regulatory Compliance.
Based on the SOE and the _ tapes, the inspector concluded that the
licensee met the reporting requirements of 50.72. However, several
items that the licensee omitted were of interest to the NRC. The.
licensee made the. red phone report at 1:19 p.m. The licensee failed to
mention that:
HPCI flow oscillations had occurred.
HPCI and RCIC had tripped on high level.
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Diesel Generators 3 and 4 had started.
RPS MG Set B output breaker had stuck in the tripped condition.
Problems with nuclear instrumentation.
The inspector discussed the reporting requirements with the licensee,
placing emphasis on what NRC actions are based on the licensee's
report. The licensee acknowledged the inspector's comments. The
licensee stated that the report was frank, honest and included those -
items that they felt were relevant to the event. The licensee will,
however, evaluate the inspector's concerns with respect to reporta-
bility.' The inspector has no further questions at this time.
c. HPCI Oscillations
HPCI flow oscillations occurred when the operator shifted the system
to the CST recirculation mode. In that mode', the bypass to the CST
,
(E41-F008) is throttled while the injection path is opened, controlling
reactor pressure. OP-19, HPCI Operating Procedure, Rev. 7 for Unit 1
and Rev.' 52 for Unit 2, address operation in the CST recirculation mode
in Section 8.2. Valve operations are specified in Section 8.2; however,
automatic controller operation and methods used to minimize oscillations
are not covered in OP-19. Reactor pressure control by HPCI is required
.in the licensee's Emergency Operating Procedures. While the inspector
concluded that OP-19 was sufficient to meet regulatory requirements,
further procedure enhancements concerning HPCI pressure control
operation may aid operators to prevent oscillations. The licensee has
committed to include revisions to OP-19 in this area. This is an
Inspector Followup Item: OP-19 Revisions for HPCI CST Recirc. Mode
(325/86-24-04 and 324/86-25-04).
d. HPCI F008 Torque Switch Settings
The licensee found an error in the Unit 1 and Unit 2 valve torque
switch settings. To verify that no hardware problem caused the HPCI
oscillations, the licensee conducted special procedure 1-SP 86-080 on -
September 20, 1986. F008 and F011, the redundant isolation to the CST,
failed to completely close during the test. The licensee tried to shut
the valves while flow was returning to the CST. Further licensee
investigation showed that:
(1) The 1-F008 torque switch settings and spring pack were not matched.
There were two possible spring packs. For the installed spring
~
pack, a torque switch setting of 3.5 was required. The licensee
found a setting of 2.0 in the field.
(2) 2-F008 torque switch setting had to be increased from 2.25 to 2.5.
(3) 1-F011 torque switch setting had to be increased from 2.0 to 2.5
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A higher torque switch setting for a given spring pack increases the
torque value that will open the switch, increasing the thrust on the
valve before the motor is de-energized. Both the F008 and F011 valves
are normally closed and receive a check closed signal upon HPCI auto-
initiation. Any previous, safety . concern regarding these valves is
therefore small.
The inspector questioned the licensee regarding continued operation of
the units with possible torque switch setting problems. The licensee
stated that there was no immediate concern regarding motor-operated
valves because:
(1) They had no other indication that the problem went beyond the F008
and F011.
(2) Most torque switches were bypassed in- the open direction. In
most cases, the open direction is the safety-related function
direction.
(3) The test schedule and scope for HPCI and RCIC will be resolved as
part of IEB 85-03.
(4) Certain safety system valves are already in their safety function
position.
The inspector reviewed the licensee's actions and decisions in this
area. While the inspectors have no further comment now, further
NRC inspections -in this area will be~ conducted as part of IEB 85-03
follow-up,
e. LPRM Problems
Inspectors will continue to followup on long term resolution of detector
failures.
No violations or deviations were identified.
13. TMI Action Plan Items
The inspectors reviewed the licensee's current status of TMI Action Plan
Items in order to plan future inspection activities. The following items
are still open:
I.C.1.2.B
I.C.1.3.B Inadequate Core Cooling / Revise Procedures (Units 1 and 2).
The licensee has completed implementation of the upgraded
Emergency Operating Procedures (EOP) required by NUREG-0737,
Supplement 1, Requirements for Emergency Response Capability
(Generic Letter 82-33) through revision 3 of the E0Ps.
Revision 4 of the owner's group guidelines have been submitted
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to NRC. Upon approval, the licensee will upgrade the E0Ps to
conform to the new guidelines. This item will be inspected
after incorporation of the revised guidelines.
I.D.2.2
I.D.2.3 Install and Implemot the Safety Parameter Display System
(SPDS) (Units 1 and 2).
This item is c- the lising schedule. Unit 1 and Unit 2
completion date - are July 28, 1989 and December 23, 1988,
respectively.
II.E.4.1.2 Dedicated Hydrogen Penetrations.
The licensee installed modifications80-133 and 80-134 on
Unit 1 and Unit 2. The' modifications were declared operable
on October 16, 1985, and May 30, 1986 on Units 1 and 2,
respectively. Licensee paperwork closeout of this item is
in progress. Awaiting inspection.
II.E.4.2.7 Containment Isolation Dependability - Radiation Signal on
Purge Valves (Units 1 and 2).
The licensee submitted the design to NRR on August 26, 1986.
Pending approval, the licensee plans to install the modifi-
cations during Refuel 5 for Unit 1 (February to July 1987)
and Refuel 7 for Unit 2 (January to May 1988).
II.F.2.3.B Install Level Instruments for Detection of Inadequate Core
Cooling (Units 1 and 2).
In a letter to NRR dated December 19, 1985, the licensee
committed to install two uncompensated condensing chambers in
the drywell and route the reference legs outside containment.
The licensee plans to start the modifications, 1-86-007 and
2-86-008, during Refuel 6 for Unit 1 (December 1988 to
May 1989) and Refuel 7 for Unit 2.
II.K.3.16.8 Challenges and Failures of Relief Valves - Modify (Units l'
and 2).
The licensee has changed the Safety Relief Valves (SRV) in.
both units from the three stage Target Rock to the two stage
Target Rack. On March 12, 1984, NRR sent to the licensee a
generic safety evaluation performed by the BWR Owners Group.
This evaluation endorsed three specific modifications along
with establishment of an effective Preventive Maintenance
(PM) program. The licensee was requested to respond to the
evaluation.
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In a. letter to the licensae dated November 14, 1984,.NRR
concluded that the actions taken or committed to be taken
would achieve the objectives of NUREG-0737, Item II.K.3.16.
The inspector reviewed the actions. First, an ongoing
preventive maintenance program using input from the BWR
Owners Group, General Electric, and Target Rcck has been
established. All SRVs are being removed and tested during
that units refueling outage. The status of the three specific
modifications was as follows:
1) E0P-01 has incorporated the manual equivalent of the
low-low' set relief concept to achieve the goal of an
order magnitude reduction in probability of a stuck open
relief valve event. This feature lowers the reseat
pressure of the SRV. A selected SRV is manually held
open by an operator beyond the reclosure setpoint. This
results in a longer blowdown, lowered reseat pressure,
and reduces subsequent.actuations of SRVs.
2) The SRV simmer margin was increased. The simmer margin
is the difference between the SRV set pressure and the
reactor -operating pressure. This modification will
minimize leakage and reduce the potential for ' spurious
opening.
3) The modification to change the main steam isolation-
valve closure on low reactor water level from Level 2 to
Level 3 was not done. The licensee response. to NRR
stated that this modification was being reviewed as part
of the ongoing Torus Integrity Program. The inspector
requested that the licensee provide the inspector with
documentation of the review.
II.K.3.18.C Modify Automatic Depressurization System (ADS) Logic (Units 1
and 2).
Awaiting NRC inspection.
II.K.3.28 Qualification of ADS Accumulators (Units 1 and 2).
!
The Nitrogen Backup System has been installed on both units.
However,. Generic Letter 84-09, Recombiner Capability Require-
ments of'10 CFR 50.44(c)(3)(ii), also addresses issues which
affect the design of the Nitrogen Backup System. This item
will be inspected after NRR approval of the design and any
subsequent modifications.
II.K.3.57 Manual Actuation of ADS (Units 1 and 2).
Will be resolved as part of the I.C.1 (see above) E0P review.
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III.A NUREG-0737 Supplement 1, Final Emergency Response Facility
Approval.
Awaiting Safety Parameter Display System (SPDS) installation
completion.
III.A.1.2.3 Modify Emergency Support Facilities (Units 1 and 2).
Modifications complete with the exception of the SPDS. See
Item I.D.2.2.3.
III.A.2.4 Installation of Emergency Preparedness Hardware and Software
(Units 1 and 2).
Awaiting SPDS completion.. See Item I.D.2.2.3.
,
III.A.2.5 Emergency Preparedness - Full Capability for Facilities
(Units 1 and 2).
Regional inspections have been performed in this area.
Awaiting.SPDS completion. See Item I.D.2.2.3.
III.D.3.4 Control Rocm Habitability Modifications (Units 1 and 2).
Awaiting.NRR Safety Evaluation Report.
The following TMI Action Items are closed:
II.F.1.2.B.2 Implementation of Long-Term Iodine / Particulate Sampling
(Units 1 and 2).
The licensee has implemented calibration procedures to comply
with the current 18 month calibration frequency of TS Table
4.3.5.9. The applicable procedures are Periodic Test PT-71.0,
General Atomic Stack Radiation Monitor Channel-Calibration,
and PT-73.2, Gene ~ral Atomic Turbine Building Radiation
Monitor Channel Calibration. These procedures have been
performed during.the last 18 month interval.
II.F.1.4 Containment Pressure Accident Monitoring (Units 1 and 2).
Instrument CAC-PI-4176 was declared operational on
December 21, 1981 for Unit 1 and 2. The instrument range
is -5 to +245 psig. A Safety Evaluation Report (SER) was
completed on this item on July 30, 1984, and ~found no
outstanding items. PT-56-6PC, Post . Accident Containment
Pressure Loop Calibrations, was implemented on April 6, 1983.
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II.F.1.5 Containment Water Level Accident Monitoring (Units 1 and 2).
Instrument CAC-LI-2601-1 was declared operational on July 23,-
1983 for Unit 1 and PM-80-078 for Unit 2 on December 21, 1981.
An SER performed on this item on July 30, 1984, determined
this item acceptable with no outstanding items. PT-56.2,
Suppression Chamber Level Loop Calibration, implements the
requirements of technical specification 4.3.5.3-1(3).
II.F.1.6 Containment Hydrogen Accident Monitoring (Units 1 and 2).
The range of the instruments was 30% for hydrogen and 25%
for oxygen concentration. An SER performed on July 30, 1984,
concluded there were no outstanding items. Plant Modifica-
tion 80-032 placed in operation these instruments on July 22,
1983, for Unit 1 and for Unit 2 .on -October 1, 1984.
PT-55.4PC-1A, Drywell Hydrogen and Oxygen Analyzer Channel
Calibration, implements the technical specification require-
ments.
No violations or deviations were identified.
14. Site Work Force Control Group (SWFCG) Meetings (62703)
The licensee uses the SWFCG to coordinate various maintenance activities -
corrective, preventive, and surveillance - within system outage windows
during plant operation. The SWFCG consists of all site organizations
involved in the work control process: operations, maintenance, technical
support, fire protection, construction, and ALARA group. The unit- super-
visors from these groups submit work activities one week in advance so
that all work on a specific system can be accomplished during the same TS
LC0 outage. The licensee plans to reduce repeated clearances and LCOs with
this planning process. The work items have been pre-approved using this
process. Work for the following day is submitted to the unit operations
engineer who delivers the' work packages to the appropriate operations shift
foreman. The package is reviewed and approved. The maintenance individual
picks up the approved package the following morning at the control ~ room and
starts work.
The inspector attended four Unit 2 SWFCG meetings during the week of
September 7,1986. The licensee gave appropriate attention to safety-
related maintenance activities during the meetings.
No violations or deviations were identified.
15. Internal Exposure Control and Assessment (83525)
The inspector attended the licensee's respiratory protection class on :
September 12, 1986, at 9:00 a.m. The class saw a videotape, received l
standard classroom instruction, and took a short quiz. The inspector '
questioned whether the licensee met a requirement to advise respirator
users when they can leave an area. 10 CFR 20.103(c)(3) states- !
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The. licensee shall advise each respirator user that the user may leave
the _ area at any time for relief 'from respirator use in the event of
equipment malfunction, physical or psychological distress, procedural
or communication faOure, significant deterioration of operating
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conditions, or any other condition that might require such relief.
The training film, viewed by the inspector, states:
In fact, at the first sign that you feel nauseous, dizzy, fatigued,
or you suspect that jour respirator is not operating properly, leave
the area. Remember it is always best to leave the area with your
respirator on, but, if you suddenly have difficulty breathing while
wearing a respirator, remove it then immediately leave the area.
The instructor's training guide, E&RC-0220, Respiratory Protection Program,
Appendix K, BSEP Respiratory Protection Training, states:
Explain that workers can leave the area anytime breathing resistance is
felt, it malfunctions, if. he finds himself becoming nauseous or sick,
or if he experiences physical and/or mental discomfort.
However, the instructor did not discuss the above item in class. Even if
the E&RC-0220 statement was read in class, not all the elements contained in
10 CFR 20.103(c)(3) would have been explicitly addressed.
The licensee issued Operating Experience Report (0ER) 2-86-34 to address the
inspector's concerns.
The licensee has placed additional emphasis in the E&RC-0220, Appendix K
lesson plan on 10 CFR 20.103(c)(3). A statement of the regulations was
added to the back of the quiz sheet for each potential respirator user
to read and sign. Also, revisions to the booth fit procedure, E&RC-223,
require the instructor to discuss the requirements of the regulation more
fully with the user.
The E&RC manager has issued a memo for all supervisors to discuss the
regulation with their employees.
Based on review of the licensee's actions and interviews with plant
personnel, the inspector concluded that licensee respirator users are
adequately advised under what conditions they may leave an area for relief.
No violations or deviations were identified.
16. Plant Modifications (37700)
The inspector rriewed plant modifications to verify that the changes were
made in accordance with TS,10 CFR 50.59, and ENP-03, Plant Modification
Procedure, Rev. 32. The inspector verified that: modifications were
controlled with approved procedures, drawing change requests were submitted,
maintenance procedures were identified for change and, when required, design
changes were included in the annual 10 CFR 50.59 report. Post-modification
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. test records -were reviewed to verify that the scope of the testing was
appropriate and that test results met previously established acceptance
criteria. The inspector reviewed the following plant modifications:
82-079 Unit 1 Standby Liquid Control Heat Trace Operability
Monitoring.82-291 Unit 1 480 V E21-F015A and B Circuit Breaker Changeout.85-069 Unit 2 Drywell Head Stud Upgrade.
No violations or deviations were identified.
17. Review of Maintenance Experience Report Associated with August 23, 1986
Unit 2 Scram
The subject scram is described in inspection report No. 324/86-22. Personnel
actions involved with the event were investigated and reported in Maintenance
Experience Report (MER)86-023. The report concludes that the technician
involved did not perform step F.1 of procedure MI-03-1BX14 before returning
the B21-PT-N023B transmitter to service. The step requires adjustment of
the pressure source to that of the reactor prior to valving in the-instrument.
The' technician omitted the step, thereby causing an instrument reference leg
pressure spike and, hence, the scran. The involved individual was counseled.
The inspector reviewed MERs and LERs issued during 1985 and 1986 to determine
if a similar event involving I&C personnel had occurred in the recent past.
None was found. Because the inspector believes that this is an isolated
event, it is not indicative of a programmatic weakness, no Notice of
Violation will be issued.
No violations or deviations were identified.
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