ML19352B102
| ML19352B102 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 05/12/1981 |
| From: | Architzel R, Callahan C, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19352B098 | List: |
| References | |
| 50-317-81-07, 50-317-81-7, 50-318-81-07, 50-318-81-7, NUDOCS 8106030085 | |
| Download: ML19352B102 (21) | |
See also: IR 05000317/1981007
Text
50338-79-11-07
60318-81-03-07
'
50320-79-03-28
81-03-04
,
,
50317-81-01-16
81-03-01
81-03-15
81-02-04
' h.
U.S. flVCLEAR REGULATORY COMMISSI0fl
81-02-17
81-03-05
81-02-05
81-03-15
0FFICE OF IllSPECTI0ft Atl0 EllFORCEMEllT 81-02-12
81-03-07
81-02-13
81-03-08
Region I
81-02-17
81-03-09
50-317/81-07
81-02-27
50317-81-03-04
Report flo. 50-318/81-07
81-02-26
50-31/
81-03-05
Docket flo. 50-318
60-05-20
C
UP K-b 4
C
License flo. DPR-69
Priority
Category
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Licensee:
Baltimore Gas and Electric Company
P.O. Box 1475
Baltimore, Maryland
21203
Calvert Cliffs Nuclear Power Plant, Units 1 and 2
Facility Name:
Inspection at:
Lusby, Maryland
Inspection conducted:
March 2-April 5,1981
8. 6. A M , h. , k
$j et/sl
Inspectors:
date signed
R.E. Architzel, Senior Resident Reactor Inspector
f' O. A h , L
,k
S /r2 /s /
"
C.J. Callahan, Resident Reactor Inspector
,
date signed
9. O. & M , h .
r/ nits
Approved by:
9""
E.C. McCabe, Jr., Chief, Reactor Projects
Section 28.
Inspection Summary:
Inspection on March 2-April 5,1981 (Combined Report Nos. 50-317/81-07 and
50-318/81-07
Areas inspected:
Routine, onsite regular and backshift inspection by the
resident inspector (55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br />, Unit 1; 54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br />, Unit 2).
Areas inspected
included the control room and the accessible portions of the auxiliary,
turbine, service, and intake buildings; radiation protection; physical
security; fire protection; plant operating records; maintenance, surveillance
testing, IE Bulletin 80-06, Licensee Action on NUREG 0660, TMI Action Plan,
and reports to the NRC
Noncompliances: One (Onit 1-Failure to follow shift relief turnover pro-
cedure, paragraph 3).
Region I Form 12
(Rev. April 77)
81060300 W
,e
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DETAILS
1.
Persons Contacted
The following technical and supervisory level personnel were contacted:
G.E.
Brobst, General Supervisor, Chemistry
D . E .' Buffington, Fire Protection Inspector
J.T.
Carroll, General Supervisor, Operat!ons
S.M.
Davis, Senior Engineer, Operations
R.E.
Denton, General Supervisor, Training / Technical Services
C.L.
Dunkerly, Shift Supervisor
W.S.
Gibson, General Supervisor, Electrical & Controls
J.E.
Gilbert, Shift Supervisor
R.P.
Heibel, Principal Engineer, Technical Support
J.R.
Hill, Shift Supervisor
L.S.
Hinkle, Supervisor, Instrument Maintenance
S.E.
Jones, Supervisor, Training
J.F.
Lohr, Shift Supervisor
R.O.
Mathews, Assistant General Supervisor, Nuclear Security
N.L.
Millis, General Supervisor, Radiation Safety
E.T.
Reimer,. Plant Health Physicist
J.E.
Rivera, Shift Supervisor
P.G.
Rizzo, Assistant General Foreman, Maintenance
L.B.
Russell, Plant Superintendent
R.P.
Sharanko, General Foreman, Production Maintenance
J.A.
Snyder, Supervisor Instrument Maintenance
J.A.
Tiernan, Manager, Nuclear Power Department
R.L.
Wenderlich, Engineer, Operations
J.M.
Yoe, Instructor, Training
D.
Zyriek, Shift Supervisor
Other licensee employees were also contacted.
'
2.
Licensee Action on Previous Inspection Findings
(Closed) Noncompliance Item (50-317/80-13-04, 50-318/80-12-04) Failure
to obtain AGF review of completed maintenance procedures and failure
to file completed maintenance procedures and check off lists.
The in-
spector reviewed the procedures associated with this item.
The licensee
has established the position of principal administrative clerk with
the responsibility of conducting a final review of work packages prior
to microfilming. Maintenance history can be retrieved by system
number from either the hard copy files or microfilm.
Specific detailed
written instruction: and checklists are currently utilized to insure
the completeness and accuracy of all safety related work packages.
The licensee had committed to taking these actions in their letter to
the NRC dated November 7, 1980.
.
.
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3
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(Closed) Unresolved Item (317/81-02-02; 318/81-02-02)
Implementation
of TMI Action Plan Item 1.C.6, Verify Performance of Operating Act-
ivities._ The NRC has developed a special tracking system for TMI
Action Plan items.. Item 1.C.6 is closed administrative 1y as an unreroived
item and is considered as an open TMI Action Plan item. (Paragraph 11
contains additional inspection results on TMI Action Plan items.)
(Closed) Unresolved Item (318/81-04-01) Boric Acid Storage Taak Room
Cleanliness.
The inspector toured the room with the licensee and
examined corrective action to date and planned future action.
Ti.e
r
licensee has mechanically clea'ned the Boric Acid buildup from the
floor and supports and has additionally neutralized the salts with
sodium phosphates. Only minor pitting was observed on the supports
and they appeared structurally sound. The licensee stated that additional
actions planned included s.rface preparations of the affected areas
(sand blast, etc) and reptinting of the supports, followed by a similar
program on the Unit 2.
Licensee actions in this area will be inspected
during future routine NRC inspections.
(Closed) Unresolved Item (318/80-22-01) No written Procedure to
Control Deactivation of Control Room Annunciates.
The licensee has
implemented a new instruction, CCI 306, Alarm A: nunciator Control,
dated March 13, 1981. The procedure addresses necessary controls for
deactivating alarms and maintaining a status log. Weekly verification
of the status of deactivated alarms is incorporated.
(Closed) Inspector Follow Item (317/81.02-04; 318/81-02-03) Corrosion
of Carbon Steel RCS Components.
The licensee shutdown Unit 1 during
the end of the report period, for inspection of hydraulic snubbers.
.
During this shutdown the Mirror insulation surrounding suction piping
for two RCP's was removed. The pumps selected were those which had
experienced steel corrosion. Corrosion of suction pipe welds similar
to that identified in the Unit 2 pump suctions was not present.
In
addition, the licensee prepared an internal report deta ling the history
of recent carbon steel fastener corrosion problems.
The inspector
forwarded the report (dated March 5, 1981) to the NRC Office of Analysis
and Evaluation of Operating Data and to IE Headquarters.
The licensee
performed a comprehensive visual examination of carbon steel fasteners
(described in the internal report) and plans to include the visual
exams in future ISI examinations.
The NRC is evaluating code requirement
changes to incorporate such inspections.
3.
Review of Plant Operations
a.
Plant Tour
At various times the inspector toured the facility, including the
Control Room, Auxiliary Building (all levels, no High Radiatinn
Areas),-_ Turbine Building, Outside Peripheral Area, Security
Buildings, Health Physics Control Points, Diesel Generator Rooms,
Service Building and Intake ;*:acture.
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Sampling checks of the following were made.
j
Radiation controls established by the licensee, including
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posting of radiation areas, conditions of step-off pads and
disposal of protective clothing.
Control Room manning, including observation of shift turn-
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over and panel welkdowns.
Systems and equipment checks for .luid leaks or abnormal
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piping vibration.
Seismic restraint and hydraulic snubber checks to verify
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adequate installation and fluid levels.
Plant housekeeping conditions, including general cleanliness
--
and storage to preclude safety or fire hazards.
Control Room and local monitoring instrumentation for various
--
components and parameters were observed, including reactor
power level, CEA positions and safety-related valve position
indication.
Whether proper access controls were established.
--
The inspector conducted a review of the licensee's lifted wire
and temporary jumper logs to verify that they are not used to
accomplish design changes or bypass safety related functions.
l
The following lifted wire and jumper permits were in effect at
the close of this report period. No items of noncompliance were
identified.
LW-2-81-47
Clear hanging alarms on both units CVCS let-
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LW-1-81-7
down relief valve position indication due to
grounds on the PI microswitches.
The licensee
is considering installing replacement valves
to eliminate recurring problems.
LW-2-78-18
Eliminate the metroscope input from part
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J-2-78-17
length CEA position circuitry.
FCR 79-99 has
been issued to provide a permanent modification.
This FCR has been completed on Unit I and
expected to be completed on Unit 2 by April
15, 1981.
LW-1-76-58
Cabling to the circulating water discharge
--
radiation montior is not terminated because
of a faulty cable. The licensee stated that
this instrument has never been operational.
The licensee has been requested to restore
this circuit to operation.
The system is not
considered safety-related and is not covered
by technical specifications.
This item is
unresolved (317/81-07-01).
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5
LW-t-80-59
Prevents inadvertant operation of RCS vent
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LW-2-81-45
valves.
Safety grade installation to replace
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existing control grade equipment is required
to complete the associated FCR.
(Committment
to NRR to deactivate circuit pending review.)
LW-1-81-1
Disables containment purge valves. An FCR
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LW-2-81-4
has been completed to upgrade the valve sole-
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noids.to meet environmental qualification re-
quirements.
The licensee is conducting an
analysis to determine if the system can be
restored to operation'without further modification.
J-1-80-57
Completed instrument loops while installing
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instrumentation in the Technical Support
Center.
J-1-81-17
Remove failed RTD 1-TE-122CB input to thermal
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margin calculator.
This condition results in
a single input vice original auctioneered
design.
Scheduled for replacement during
April, 1981 outage.
J-1-81 22
Eliminates low flow input to chargir.g flow /
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press low (F-45) annunciator to prevent
.
masking low charging pressure alarm. An FCR
has been initiated for replacement of the
original design flow transmitter with a unit
which is less susceptable to pressure surges.
LW-1-81-8
Eliminates failed.Tc RTO 1-TE-112CD input to
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RPS channel D.
The licensee expects to
replace the failed RTO during the April
outage.
This condition results in a single
input vice the original auctioneered design.
J-1-78-1
Defeats CEA interlocks to permit preventive
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J-2-81-46
maintenance to preclude CEA guidetube thinning.
FCR-81-26 has been approved for permanent
installation of jumpers.
J-1-80-23
Permits continued operation of loop 12 sub-
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LW-1-80-22
cooled margin monitor with loop 11 monitor
out of service.
The licensee is experiencing
problems with procurement of replacement
parts.
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J-1-81-23
Eliminates annunciator input from spare
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J-1-81-24
boric acid heat tracing thermocouples. .The
.J-1-81-25
licensee has submitted an FCR to provide per-
J-1-81-27
manent installation in both units.
LW-1-81-28
Eliminates annunciator input from boric acid
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,
heat tracing thermocouples installed in an
,
inactive system.
The licensee is preparing
an FCR to provide the ability to switch out
inputs which produce invalid alarms.
9
J-2-80-10
Delete failed pressure inputs to loop 21 and
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22 subcooled margin monitors. This condition
results in a single pressure input vice the
original auctioneered design.
The following Unit I annunciators were in the alarm condition at
the close of this report period.
Power Level Rate Bypass s/u Range (D-45) The licensee has
--
been asked to submit an FCR to reverse the alarm logic.
S/G Aux Feed Disch Suct Press Low (C-69) The licensee has
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been asked to submit an FCR to require a " pump running"
input to discharge pressure low logic.
RC Loop 12 Margin to Saturation lo (E-22) MR-IC-80-154,
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Failed channel.
'
The following Unit I annunciators were out of service at the close
of this report period.
12B SI Tank Press Level LO (H-43).
MR-0-81-527.
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Radiation Monitor Level HI (F-21).
MR-0-80-06 Letdown
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Failed Fuel Element detector out of service.
11B RCP Seal Temperature High Pressure (E-51.).
MR-0-81-
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863, seal degradation.
CEA TCB 10 Open (D-4) part length CEA's removed.
The licensee
--
has been asked to submit an FCR to delete this annunciator.
The following Unit 2 annunciators were in the alarm condition at
t
the close of this report period.
Power Level Rate Bypass s/u Range (D-45.
The licensee has
--
been asked to submit an FCR to reverse the alarm logic.
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____________ --_ _______________ __-____ ____-
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7
S/G Aux Feed Disch Suct Press low (C-69).
The licensee has
--
been asked to submit an FCR to require a " pump running" in-
put to discharge pressure low logic.
Condensate Pump 011 Flow Low (c-10, c-2, c-6) To require a
--
pump running input to low flow logic.
Pump not running. The
licensee stated that normal operation requires all three
condensate pumps so that the alarm is only present reduced
power operation.
In addition they stated an FCR had been
considered several years ago which would block the alarm
with the pump not running, however because of the circuit
particulars the charge was not feasible.
The inspector
acknowledged the licensee's comments.
,
21 CHG Pump SIAS Blocked Auto Start (F-41).
MR-81-888, Leak
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on pump discharge desurger.
,
Enable MPT Protection (F-36). MR-0-81-1187, Temperature
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indicator input failed low.
Letdown RV 354 Open (F-2). MR-0-81-1155, Alarm circuit will
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not reset.
21B RCP Seal Temp Hi Press (E-56).
MR-0-80-644, apparent
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seal degradation.
Pressurizer Level Channel. x and y (E-11, E-15). MR-0-81-
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1125, apparent alarm circuit probelm.
The following Unit 2 annunciators were out of service at the
close of this report period.
22 HPSI Pump SIAS Blocked Auto Start (G-17) MR-0-79-4032,
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Pump is not in service, replacement on site.
CEA TCB-20 Open (D-4) Part length CEA's removed.
The licensee
--
has been requested to submit an FCR to delete this annunciator.
Channel A Boric Acid Heat Tracing (F-3) input from spare
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sensing circuit.
FCR in progress.
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228 RCP Bleed Off Temp HI (E-51). MR-0-80-4980, spurious
alarm.
Gland Seal Header Pressure (B-07).
MR-0-81-1178, cv valve
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failure.
21A RCP Seal Temp Press High (E-63).
MR-81-1216, degraded
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lower seal.
SEC Pre Power Dependent Insertion (D-28).
MR-81-1101, apparent
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alarm circuit problems.
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8
During a protected area tour the inspector observed that water
had accumulated in the valve pit which contains AFW system suction
valves from the Condensate Storage Tanks.
The water was several
inches above the valve bodies.
The inspector informed the shift
supervisor who stated that the pit would be pumped down and an MR
issued to clean out its drain line.
During a tour the next day
the inspector noted that there was no water in the pit.
During an Auxiliary Building tour the inspector noted that the
Hood for the IJ219 Steam Generator Blowdown and Miscellaneous
Waste Sample Sink was fouled nearly full open by several temporary
Demineralized Water Sample lines.
The hood window was above all
previous marks for maximum opening (to ensure adequate air flow).
The inspector a pressed concern to the licensee concering this
configuration. When this item was re-inspected on March 31,
1981, the licensee had removed the temporary lines, measured for
maximum opening (dated March 27,1981) and bolted the sample hood
at that point to avoid opening any further.
During a Control Room tour on April 2, 1981 the inspector noticed
that both the Reactor Operator (RO) and Unit 1 Control Room
Operator (CRO) had lef t the control room.
Both units were operating
at 100% power.
Remaining in the Contro. Room were the Unit 2
Control Room operator, the Shift Supervisor Assistant (SSA), and
the Shift Supervisor.
Investigation revealed that the Unit 1 CR0
had turned ovdr the controls of Unit 1 to the SSA prior to going
to the cable spreading room to time an Emergency Diesel Start.
The licensee stated that the CR0 had briefed the SSA on Unit
Status, discussed panel alarms, and that the SSA had looked at
the CR0 log book immediately prior to the short (less than 5
minutes) relief.
The inspector expressed concern with this
method of control room relief.
Specifically, licensee procedure
required the R0 to fill in both Units' Checkists prior to assuming
the shift and, in addition, to receive a short briefing immediatley
prior to assuming the controls for a relief of a particular
unit.
Licensee procedures were mute regarding specific requirements
for the SSA to assume the shift and relieve the CR0's.
The
inspector stated that failure to perform a comprehensive shift
turnover and relief when the SSA assumed the controls was an item
of noncompitance (317/81-07-02).
The licensee implemented on the
next shift a requirement for the SSA to complete the Senior
Control Room Operator Checklist prior to assuming the shif t and
to receive a short briefing of unit status prior to relieving at
the controls.
l
b.
Review of Operating Logs, Records
Logs and records were reviewed to identify significant changes
and trends, to assure required entries were being made, to verify
Operating Orders conform to the Technical Specifications, to
verify proper identification of abnormal conditions, and to
verify conformance to reporting requirements and Limiting
7
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9
. .
Conditions for'0peration.
The following records were reviewed
for the report period:
Shift Supervisor's Log
--
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Unit 1 Control Room Operator's Log
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Unit 2 Control Room Operator's Log
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Nuclear Plant Engineer-Operations Notes and Instructions
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Unit 1 and 2's' Control Room Daily Operating Logs (sampling
--
review)
Service Building Operator's Log
--
No items of noncompliance were identified.
4.
Review of Events Requiring One Hour Notification to the NRC
The circumstances surrounding the following events requiring prompt
NRC (one hour) notification via the dedicated telephone (ENS-
line) were reviewed.
March 4, 1981. During Mode 5 operations (Unit 2) while pre-
--
perations were being made to perform an integrated ESFAS test
(paragraph 6) an inadvertant E9FAS actuation occurred at 4:20
p.m. The actuation was caused by a defective shunt being installed
to monitor load changes in the feed to the Channel B ESFAS Actuation
Cabinent. A 4ky undervoltage actuation occurred, resulting in
starting the Emergency Diesels.
In addition, No. 22 LPSI pump
lost power.
A redundant LPSI pump (No. 21) was started within one minute to
provide shut down cooling.
The shunt was removed, reconnected,
and tne test was conducted satisfactorily.
The inspector ob-
served licensee actions in the control room.
Low level in No. 22 SG resulted in reactor trip from about 50%
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power (post refueling testing) at 4:10 a.m., 3/15.
The cause was
setpoint drift on a control oil pressure switch, and actuation of
a relay which causes Feed-Reg Valve closure.
Pressure switch
setpoint was 85 psi; it should have been 45 psi. The control oil
pressure drop occurred during thrust bearing wear trip testing
(as expected) and the out-of-specification pressure sensor initiated
the trip sequence.
Resetting was accomplished and power operation
was resumed.
At 7:30 a.m., 3/7, a controlled (Unit 1) shutdown was initiated
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to comply with the action statement fer an inoperable AFW pump.
The pump was repaired (bearing replacement) at 9:52 a.m., 3/7.
Power escalation was begun. A drop of 6-7 percent power was
involved.
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During Mode 3 (hot shutdown) testing (Unit 2) with one rod withdrawn,
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Low Steam Generator Pressure (LSGP) caused reactor trips at 12:46
p.m., 3/7, and 2:40 p.m., 3/8.
The LSGP trip setpoint had been
changed during the refueling outage from 478 psia to 570 psia to
limit the heat extraction rate during a steam line break transient
(in accordance with the safety analysis for the fuel load associated
with changing the refueling cycle from 12 to 18 months).
That
change also allowed modifying the LPSG Trip Bypass automatic
clearing setpoint from 600 psi or less to 685 psia or less.
The
auto clear setpoint was not modified, resulting in two trips.
The auto clear setpoint was then changed.
.
At 6:00 a.m., 3/9, Unit 2 containment integrity was lost for
--
about 20 seconds when the outer personnel access door opened upon
opening of the inner door, which then was shut to restore integrity.
The cause was identified as a broken door interlock (since repaired).
No. 12 S/G FRV Controller and Plant Trip on March 13,1981(11:18
--
p.m.)
The inspector reviewed the material procurement and maintenance
conducted on number 12 steam generator feed regulating valve
controller (1-FIC-1121).
First indication of a malfunction
occurred on January 16, 1981 when the feed regulating valve shut,
causing a low steam generator level trip.
Subsequent troubleshooting
identified a loose lead to a relay which initiates a close signal
to this valve upon turbine trip.
The maintenance request was
held open subsequent to additional investigation. On March 6,
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1981, the licensee initiated a priority procurement request for
a replacement controller when it was decided that sufficient data
had been collected to indicate that the problem could be due to
intermittent failure of the controller and a replacement was not
available in the licensee's inventory.
A second low steam generator
level trip occurred on March 13, 1981, when the controller failed.
Facility change request, FCR 81-24 was approved after a class II
safety evaluation (not safety-related but addressed in the FSAR)
was conducted.
This modification consisted of the installation
of a replacement controller of a different design which allowed
operation in the manual mode with the feed regulating valve
bypass in automatic.
This method results in automatic level
control within a 15% band.
Discussions were held with various
control room operators to evaluate their appreciation for shrink
and swell characteristics on a transient.
The licensee expects
to receive the correct replacement controller by April 4, 1981.
Baltimore Gas and Electric has formed a committee with the short-
term objective of identifying material held by the corporation
which can be used in the Calvert Cliffs Units.
Their long-
term objective is to produce a listing for all spare parts which
should be maintained to support the Nuclear Power. Department.
The current method of establishing spares inventory and minimum
level is based on individual supervisory recommendations.
No isems of noncmpliance were identified.
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11
5.
Plant Maintenance
During the inspection period, the inspector observed various main-
tenance and problem investigation activities. The inspector reviewed
these activiites to verify compliance with regulatory requirements,
including those stated in the Technical Specifications; compliance
with the administrative and maintenance procedures; compliance with
applicable codes and standards; required QA/QC involvement; proper use
of safety tags; proper equipment alignment and L.se of jumpers; personnel
qualifications; radiological controls for worker protection; fire
' protection; retest requirements and ascertain reportability as required
by Technical Specifications.
The following activities were included
during this review:
MR 0-81-1438, observed on March 31, 1981, Perform Smoke Test of
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Cable Spreading Rooms to ensure tight seals.
MR-81-2075, Implementing PMS 2-11-M-Q-3.
Bullet Tubes and change
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coverage, and tagging on April 1,1981.
MR E-79-212, Trouble shoot load changes in the feed to vital A-C
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busses, observed on March 4, 1981.
The inspector questioned the licensee concerning the time frame for
performance of the preventive maintenance item for cleaning the Service
Water and Component Cooling Water heat exchangers (i.e. taking one
salt water train out of service). Technicc1 Specifications allow 72
hours with one salt water System inoperable prior to shutdown.
During
observation in this inspection, the licensee was cleaning the tubes
only on the day shift and taking the full 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to complete the
task.
The inspector asked that for maintenance actions of this nature
(this maintenance is done eight times a year at Calvert Cliffs),
consideration be given to ccmpleting this task in less time due to the
large number of safety systems made inoperable by the particular
maintenance.
The licensee acknowledge the inspector's comments.
6.
IE Bulletin Followup
The inspector reviewed licensee actions on the following IE Bulletins
(IEBs) to determine that the written responsa was submitted within the
required time period, that the response included the information re-
quired including adequate corrective action commitments, and that
licensee management had forwarded copies of the response to responsible
onsite management. The review included discussions with licensee
personnel and observations and review of items discussed below.
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12
IEB 80-06, Engineered Safety Features (ESF) Reset Controls. Mod-
ifications and test procedures implementing aspects of this Bulletin
had previously been inspected (Inspection Report 317/80-16; 318/80-15.
paragraph 9).
During this inspection, the inspector reviewed Technical
Support Procedure 48, Revision 0, Modified ESFAS Logic Test (Reset),
approved January 19, 1981.
The inspector observed preparation for the
testing and auxiliary maintenance actions such as troubleshooting
to monitor channel 13 Actuation cabinet feed load changes.
Inspector
review of the test procedure revealed that the test did not retest
features in the manner described in the Bulletin. The test required
re-alignment of all affected component handswitches following actuation
of the signal in accordance with procedure checklists, prior to resetting
the signal. The licensee has modified procedures (EOP 5 Checklists)
to require placing the controls for all equipment in the actuated
(safe) position prior to attempitng a reset.
The licensee has modified
ESF reset curcuitry (see June 17, 1980 Bulletin response letter for
. listing of valves, pumps and dampers modified) to require correct
position of the component handswitch in a series arrangement prior to
allowing a reset from the control Room.
The response also addressed
valves which may change mode following reset (component Cooling Heat
Exchanger Inlet and Outlet Valves). This provision was intent.ional to
allow increased salt water flow to the component cooling heat exchanger
following SIAS reset and presents no safety problems.
In addition,
the licensee addressed three types of equipment which are prevented
from resetting by administrative procedures (In excess of the checklists
previously mentioned). These included:
Manual HPSI Header Isolation Valve (Physically Locked Open)
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Safety Injection Tank Isolation Valves (Power removed from valve
--
operators)
Containment Purge Air Supply and Exhaust Fans (Power removed from
--
fans during normal operation).
The inspector concluded that for the above listed valves, the licensee
had complied with the Bulletin's intent (the series reset interlock
was tested following completion of the FCR) or justified exception.
With respect to valves not listed in the response and which did receive
ESF actuation, the inspector stated that the test was not adequate. A
test was requested to be performed which verified that equipment would
not reposition upon reset, with reliance on administrative procedures
alone not allowed. The licensee stated that a review of schematics
and been performed and the various components fell into two categories:
those that would not reposition because of circuitry and others which
woulc but had no safety significance (tne components which would be
repositioned and had safety significance were stated to have been in-
corporated in the facility change requiring proper switch position
prior to reset).
The licensee satisfactorily completed TSP-48 as
written.
The inspector noted that this test insured that equipment
would not be repositioned if the procedures were follsed, however
,.
.
13
e
requested that the licensee develop another test which verified that,
for those valves not in the reset logic, repositioning would not occur
following reset independent of switch position.
In addition the
inspector requested the licensee to address other components which
would reposition (but stated to have ro safety significance).in a
supplemental bulletin response.
The licensee committed to performing
such a test ar.d submission of a revised Bulletin response within 90
days.
IE Bulletin 80-06 will remain open.
7.
Surveillance Testing
The inspector observed portions of the following surveillance (or
other) testing.
The inspector verified that testing was performed in-
accordance with aporoved procedures, limiting conditions for operation
were satisfied, test resu15; (if completed at time of observation)
were satisfactory, removal
nd restoration of equipment were accom-
plished and that deficienc.
identified were properly reviewed and
resolved.
The following tests were observed in this review.
Full flooding test of the :LLomatic fire suppression (Halon) system
installed in the Cable Spreading Room (CSR) to satisfy Fire Protection
Safety Evaluation Report Item No. 3.1.6 conducted on 3/15.
Both Unit
1 and 2 Halon systems were requited to be installed by 2/16/81 and
tested by 3/16/81. The test was performed on Unit 1 (to qualify both
Units) and was unsuccessful. Although all levels in the CSR itself
reached 7 percent test gas (freon), the upper section did not hold the
required concentration for 10 minutes. The upper portion of a vert-
ical cable chase exiting the CSR never reached acceptable concentrations.
Subsequent contact with NRR resulted in a revised schedule for complet-
ion of the test. A full scale retest is to be performed on April 26,
1981.
One of the reasons for the initial testing failure was that the
exhaust dampers for the Unit 1 and 2 cable spreading rooms had been
wired incorrectly. (Unit l's CSR exhaust damper was operated by Unit 2's
switch and vice versa).
The licensee identified this on 3/16 and
corrected the wiring error by 3/19/81.
The inspector also observed a smoke test of the Unit 1 and 2 CSR's
conducted on March 31, 1981 (To ensure a tight seal).
These tests were
both unsuccessful in that excessive smoke was observed in the Control
. Room. (The Control Room shares a common ventilation system with CSR's
and is isolated by dampers in the event of a fire.)
Leakage through
the Shut dampers was measured at about 1000 SCFM for the Unit 1 CSR
and 1450 SCFM for the Unit 2 CSR.
The inspector stated that satisfactory completion of the CSR automatic
Halon system would be followed by the NRC (317/81-07-03; 318/81-07-
01).
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14
8.
Review of Licensee Event Reports (LER's)
a.
The inspector reviewed LER's submitted to the NRC:RI office to
verify that the details of the event were clearly reported, in-
cluding the accuracy of the discription of cause and adequacy of
corrective action. The inspector determined whether further in-
formation was required from the licensee, whether generic im-
plications were indicated, and whether the event warranted onsite
followup.
The following LER's were reviewed:
LER N6.
Date of Event
Date of Report Subject
50-317:81-03/3L 02/17/81
03/19/81
ESFAS Channel ZD No.12
Steam Generator pressure
1-E/E-1023A isolator was
out of specification in
non-conservative direction.
50-317:81-09/3L 02/05/81
03/03/81
During investiagion of
a high Tcold input, RPS
channel D hi power Hi
startup rate low steam
generator pressure,
thermal margin / low pressure
& axial flux offset trip
'
units bypassed.
50-317:81-11/3L 02/12/31
03/13/81
During investigation-
of Reactor Protective
System Channel D Steam
Generator Pressure,
Thermal Margin / low
Pressure & Steam Generator
!
Low Pressure trip units
,
were bypassed.
50-317:81-12/3L 02/13/81
03/13/81
While shifting from 1 to
2 running charging pumps
&
'
letdown relief valve CVC-
345-RV lifted and failed
to reseat.
50-317:81-13/3L 02/17/81
03/17/81
During investigation of
'
dirty oil in #11 AFW
,
pump inboard turbine
bearing, Journal bearing
discovered damaged.
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"
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LER No.
Date of Event
Date of Report Subject
.
50-317:81-14/3L 02/27/81
03/27/81
- 12 Diesel Generator
started automatically for no
apparent reason.
50-317:81-15/3L 02/26/81
03/26/81
Sample pump for C.R. rad
monitor out of service.
,
50-317:81-16/3L 03/05/81
03/31/81
RPS Channel B Tcold in-
put TE-122CB reading
erratic causing spurious
TM/LP trips.
50-317:81-17/3L 03/04/81
04/01/81
- 12 AFW PP placed out of
service per TS 3.7.1.2 to
inspect turbine bearings.
Bearing was found scored.
50-318:81-10/3L 03/01/81
03/17/81
During mode 5, isolated
ERV-402, a power-operated
relief valve, due to
leakage past the valve.
50-318:81-04/3L 02/04/81
03/04/81
During mode 6, lost shut-
down cooling flow due to
inadvertent de-energization
of #21 120v vital AC bus:
(IR 318/81-04)
50-319:81-14/3L 03/05/81
04/03/81
4KV Busses 21 and 24
ESFAS degraded voltage re-
lays were out of calibration.
- 50-318:81-13/3L 03/04/81
04/03/81
shutdown cooling lost
during inadvertant ESFAS
actuation (paragraph 4)
b.
For the LER's selected for onsite review (denoted by asterisk),
the inspector verified that appropriate corrective action was
taken or responsibility assigned and that continued operation of
the facility was conducted in accordance with Technical Specifications
and did not constitute an unreviewed safety question as defined
in 10 CFR 50.59.
Report accuracy, compliance with current reporting
requirements and applicability to other site systems and components
were also reviewed.
..
16
LER's 317 81-13 and 81-17 concerned the discovery of damaged AFW
pump steam turbine (driver) inboard turbine journal bearings. The
inspector had previously observed maintenance activities involving
'
replacement of the Turbine bearings (Inspection Report 317/81-
04).
-
While investigating dirty oil in the inboard (pump side) turbine
journal bearing, the bearing was discovered damaged. When other
-AFW pump turbines were disassembled to cannibalize parts, similar
damage was found on all inboard journal bearings.
The damage was
caused by improper oil level in these ring lubricated bearings.
Although an about 3 inch long sight glass for oil level is supplied,
level must be maintained within a narrow band (about 1/4 inch).
The licensee thought any level in the sight glass was adequate.
Levels were not addressed in the Technical Manual. Although the
bearings were heat scored and there was babbit in the oil, the
Turbines had routinely passed surveillance testing.
The Turbines
are type GS-2 Terry Steam Turbines.
In addition to replacing the bearings, the licensee added clear
markings to the bearing's sight glass to delineate the required
control band and increased the frequency of oil change from a'
refueling outage to a monthly basis.
No items of noncompliance were identified.
9.
Observation of Physical Security
The resident inspector checked, during regular and off-shift hours, on
whether selected aspects of security met regulatory requirements,
physical security plans and approved procedures.
a.
Physical Protection Security Organization
Observations and personnel interviews indicated that a full
--
time member of the security organization with authority to
-
direct physical security actions was present, as required.
Manning of all three shifts on various days was observed to
--
be as raautred.
b.
Physical Barriers
Selected barriers in the protected area (PA) and the vital areas
(VA) were observed and random monitoring of isolation zones was
performed. Observations of truck and car searches were made.
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c.
Accuss Control
Observations of the following items were made:
Identification, authorization and badging
--
Access control searches
--
Escorting
--
Communications
--
Compensatory measures when required.
--
10. Visit by Office of Analysis and Evaluation of Operational Data Staff
The inspector accompanied members of the NRC's OAE00 staff during
eir site visit on April 1, 1981 to investigate the loss of Unit 1
arvice water subsystems and subsequent loss of Auxiliary Feedwater
(Unit 1) which occurred on May 20, 1980.
Inspection findings regarding
these events are detailed in In:pection Report 317/80-06.
11.
Licensee Action on NUREG 0660, NRC Action Plan Developed as a Result
of the TMI-2 Accident
.
The NRC's Office of Inspection and Enforcement has been assigned in-
spection responsibility for licensee implementation of selerred action
plan items. These items have been further broken down iato numbered
descriptions (enclosure 1 to NUREG 0737, Clarification of TMI Action
Plan Items).
Various licensee letters containing commitments to the
NRC were used as the basis for determining acceptability along with NRC
clarification letters and considerable inspector judgment.
The following
action plan items were reviewed during this inspection (number of
description in parenthesis).
I.A.1.1(1) -
STA; On duty Licensee status with respect to the
STA has been previously inspected.
This item will
remain OPEN pending NRC determination of equivalence of
licensee's STA program, as implemented, to a college
degree.
I.A.1.1(3) -
~STA Training requirements; The licensee has conducted
the STA training documented in Baltimore Gas and Electric
letter of December 30, 1980 for all shift supervisors
and all but three Senior Control Room Operators. Add-
itional training in thermodynamics (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />), accident
chemistry (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />), steam line break (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) and
electrical system failure analysis (8 hcurs), has been
provided in the operator requalification program.
F
18
program. The three senior licensed individuals (recently
licensed in 1980) who have not completed STA training
were restricted in watch stations to the Shift Supervisor's
Assistant Position, effective January 1,1981.
No
unacceptable conditions were identified.
I.A.2.1(4) -
Modify training; The licensee has incorporated about
40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of heat transfer, fluid flow, and thermodynamics
training in their hot license program and about 28
hours of similar advanced training in the operator
requalification program.
Lesson plan objectives are
based on the guidelines presented in enclosure 2 to the
BG&E (!!.R. Denton) letter of March 28, 1980. A 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />
taining program designed to meet the requirements of
enclosure 3 to the letter is being prepared by Combustion
Engineering and is expected to be available in lesson
plan form for delivery in class during September / October
of this year. Additional hot license and requalification
training is being provided to enhance the operators'
and prospective operators' knowledge of significant
licensee event reports. The requirements of enclosure 4
to the letter have been incorporated in the licensee's
simulator training program.
No unacceptable conditions
were identified.
Shift Manning; (1) Limit Overtime.
The licensee's re-
I.A.1.3
-
sponses dated December 30, 1980 and January 31, 1981,
stated that they intended to comply with the NRC position
on overti.ne with the following exception.
NUREG 0737 provides for a break of at least twelve (12) hours, (which
can include shift turnover time) between all work periods.
Current
administrative procedures require that this limitation be normally ad-
hered to the work periods including safety related functions.
However,
to preclude undue stress on the shift manning rotation, an exception to this
rule has been made in the case of two (2) work periods separated by
only eight (8) hours. :s long as neither of these two (2) work periods
exceed ten (10) hours in length and does not involve any one in-
dividual with a frequency of greater than once in one payroll week
period, and further meets the guidelines of:
1.
An individual should not be permitted to work more than twelve
(12) hours straight (not including shif t turnover time),
2.
An Individual should not work more than seventy-two (72) hours in
one payroll period, and
3.
An individual should not be required to work more than fourteen
(14) consecutive days without having two (2) consecutive days
off.
(For the purposes of this guideline, a " day" of work is
considered to be one in which the individual works for more than
four (4) hours in one day).
,,
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19
BG&E feels that this exception is highly desirable and beneficial to
operating personnel, in that the additional scheduling flexibility
allows them to minimize instances where personnel need to be called in
on days off, or in the middle of the night, interrupting their planned
rest periods. This provision further enhances planned rest periods by
allowing minor schedule changes to lengthen vacation periods as desired
by operating personnel.
.
The inspector reviewed the above exception, concluded that this was a
reasonable deviation, that it met the NUREG-0737 guidance of deviations
authorized by the Plant Superintendent, and that it was in accordance
with published procedures.
The inspector reviewed CCI 140A, Shift Staffing and Overtime, dated
January 28, 1981. One additional area of deviation with the NRC
Guidance was noted. The licensee's requirement restricting time to
not more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in one payroll week would allow, for example
(considering other restraints), twelve-consecutive days of twelve
hours each, if the first day of a two week work period and the last
. day of the next period were off.
This would entail six consecutive
days where the time worked would be 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> in seven day periods.
The inspector noted that NRC guidance was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> maximum in any
seven day period.
The licensee stated the reason for choosing this
method was for ease of auditing. The licensee stated that CCI 140A
would be revised to conform to the literal wording of NUREG 0660 with
respect to the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7 day period.
Item I.A.1.3 will remian
open pending revision of CCI 140A.
I.C.2
Shift and Relief Turnover Procedures.
The licensee's im-
plementation of this item had been previously inspected with
respect to licensed personnel (Inspection Reports 317/80-08;
318/80-08, 317/80-16; 318/80-15, 317/81-02; 318/81-02).
During this inspection, turnover procedures for other tech-
nicians were examined.
The licensee does not presently have
on-shift I&C technicians, electricians, or mechanics. Each of
the shops in these categories use active work center log
books to track ongoing activiites on a daily basis.
The
inspector reviewed the log books to track ongoing activities
on a daily basis and determined that this was an adequate
work status system in lieu of turnover checi / procedures
when these-functicas are not on shift.
Radi.*. ion Control
technicians maintain a RADCON Smooth Log and rJOCON Shift
Supervisor Turnover Log Book.
Chemistry technicians maintain
a Chemistry Smooth Log to record shift activities. Both
Radiation Control and Chemistry technicians are on shift at
Calvert Cliffs and the log book method is an acceptable
implementation of Item I.C.2.
.
.
.
20
With respect to implementation for operations, the inspector
noted that the turnover checklists were implemented via the
GS-0 Standing Instrucions (only).
The inspector stated that
complete implementation of Item I.C.2 required incorporation
of the checklists and requirements to use the checklists
into permanent plant procedures.
The licensee stated that
the procedures would be appropriately revised.
Item I.C.2
remains OPEN pending revision of permanent plant procedures.
I.C.5
Feedback of Operating Experience; Implement Procedures.
The
licensee has created a standing committee to implement the
recommendations of I.C.S.
The inspector reviewed the requirement
in (new) procedure CCI 139B, Organization and Operation of
the Plant Operating Experience Assessment Committee (POEAC),
dated January 14, 1981.
In addition, the inspector discussed
POEAC activities with the Chairman and discussed selected
events at other sites with other members when approached by
them.
No unacceptable conditions were noted regarding
implementation of I.C.S.
Routine inspection of POEAC activities
will ce conducted in furture NRC inspections.
A.1.2
Upgrade Emergency Support Facilities-Item 1.8 EOF.
The in-
spector toured the Interim EOF facilities with a licensee
representative.
These facilities are addressed in the
licensee's Emergency Response Plan, Revision 0, dated December
31, 1980, which has been submitted to the NRC.
The interim
EOF (Appendix J-5) is designated as the Emergency Control
Center. The licensee has made separate provisions for a
Media Communication's Center (Prince Frederick Fairgounds)
which provide for rapid and accurate distribution of information
to the media.
The inspector observed these facilities,
which include a 200 line telephone cable termination, the
" VIP" Building (including six dedicated telephone instruments),
and a hot line to the other emergency centers.
The Alternate Emergency Control Center (Farm Equipment
Building) was undergoing major modifications, including
installation of communications equipment, data transmission
equipment, etc. The inspector made arrangements to relocate
the ENS network to the Site Emergency Coordinator's Room and
to place the Health Physics Network telephone in the
radiological assessment area.
The Emergency Control Center (South Service Building, Classroom
1) was also inspected and contained adequate communications
capabilities and space to satisfy the Interim EOF requirements.
No unacceptable conditions were identified with respect to
the Interim EOF facilities.
The licensee has not finalized
plans for a permanent EOF.
Initial plans-in favor of an EOF
in the basement of the proposed simulator building have
apparently been dropped in favor of plans to purchase land
and construct an ECF in the Prince Frederick area, approximately
10 miles from the plant.
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21
12.
Review of Periodic and Special Reports
,
-Upon receipt, periodic and special reports submitted by the licensee
pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed by
the inspector.
This review included the following considerations:
The report includes the information required to be reported by NRC
,
requirements; test results and/or supporting information are consistent
-with design predictions and performance specifications; planned corrective
action is adequate for resolution of identified problems; deterniination -
whether any information in the report should be classified as an ab-
normal occurrence; and the validity of reported information. Within
the scope of the above, the following periodic reports were reviewed
by the inspector:
.
February,- 1981 Operations Status Reports for Calvert Cliffs No.1
--
Unit and Calvert Cliffs No. 2 Unit, dated
Results of Steam Generator Eddy Current Examination at Calvert
--
Cliffs Unit 1, 1980, BG&E letter dated March 5, 1981.
Report on Alterrative Safe Shutdown at Calvert Cliffs Nuclear
--
Power Plant, Units 1 and 2, BG&E letter dated March 19, 1981.
13. Unresolved Items
Unresolved items are matters about which more information is required
to determine whether they are acceptable, items of noncompliance or
deviations. Unresolved items addressed during this inspection are
discussed in Paragraph 3 of this report.
14' .
Exit Interview
-
Meetings were held with senior facility management periodically during
the course of this inspection to discuss the inspection scope and
l
findings. A summary of inspection findings was also provided to the
'
licensee at the conclusion of the report period.
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