ML20010D059
| ML20010D059 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 08/05/1981 |
| From: | Architzel R, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20010D051 | List: |
| References | |
| 50-317-81-13, 50-318-81-13, NUDOCS 8108210410 | |
| Download: ML20010D059 (16) | |
See also: IR 05000317/1981013
Text
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50320-79-03-28 's
50317-81-05-06
50317-81-06-13>'
50317-81-06-12
50317-81-05-15
50318-81-06-01
50317-81-06-01
50317-81-05-21
50318-81-06 26
5'317-81-06-26
50317-81-05-26
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50317-81-06-3G
50317-81-06-01 (,
50318-81-07-03
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0
50318-81-07-04
5031'-81-06-13
50317-81-06-12>
50318-81-06-13
50317-81-05-27
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50317-31-05-08
U.S. NUCLEAR REGULATORY COMMISION
OFFICE OF INSPECTION AND ENFORCEMENT
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Region I
50-317/81-13
Report No.
50_-318/81-13
50-317
Docket No.
50-318
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License No. DPR-69
Priority
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Category
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Licensee:
Bc1timore Gas and Electric Compar,y
P. O. Box 1475
Baltimor_e, Maryland 21203
Facility Namc:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2
Inspection At:
Lusby, Maryland
Inspection Corducted: June 1 - July 5,1981
Inspectors:
8. C. A M }
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8l5'l 81
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R. E. Architzel, Senior Resident
date signed
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Reactor Inspector
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Approved by:
@E1M
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date signed
915"I B\\
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E. C. McCabe, Jr , Chief Reactor
Projects Section 2B
In_spection Summary:
Inspection on June 1 to July _5,___ 'l (Combined Report Hos. 50-317/81-13
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and_50-318/81-13)
8108210410 810807
PDR ADOCK 05000317
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Areas Inspected:
Routine, onsite regular and backshif t inspection by the
resident inspector (42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br />, Unit 1; 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-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; plant maintenance,
surveillance testing, IE Circulars, TMI Action Plaa Item I.C.6, and reporting
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to the NRC.
Noncomaliances:
Two (Failure to return RWT level switch to service following
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surveillance test, paragraph 3, and adjustment of 11 MSIV stroke speed without
a maintenance request, paragraph 4).
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DETAILS
1.
Persons Contacted
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The following technical and supervisory level personnel were contacted:
G. E. Brobst, General Supervisor, Chemistry
J. T. Carroll, General Supervisor, Operations
J. A. Crunkleton, Supervisor, Electrical Maintenance
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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
S. Hager, Site Representative, Combustion Engineering
R. P. Heibel, Principal Engineer, Technical Support
J. R. Hill, Shift Supervisor
J. F. Lohr, Shift Supervisor
R. O. Mathews, Assistant General Supervisor, Nuclear Security
N. L. Millis, General Supervisor, Radiation Safety
J. E. Rivera, Shift Supervisor
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L. B. Russell, Plant Superintendent
R. P. Sheranko, General Foreman, Production Maintenance
J. A. Snyder, Supervisor Instrument Maintenance
T. L. Sydnor, General Supervisor, Operations QA
J. A. Tiernan, Manager, Nuclear Power Department
R. L. Wenderlich, Engineer, Operations
D. Zyriek, Shif t Supervisor
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Otner licensee employees were also contacted.
2.
Licensee Action on Previous Inspection Findings
(Closed) Unresolved Item; Submittal of ISI Exemption Request. This item
addressed the requirement of 10 CFR 50.55a(g)(5)(iii) to submit exemption
requests for those items of the code which are considered impractical for
the licensee.. The licer 2e has submitted the exemption requested in a
letter to the NRC (N9D ..perating Reactor Branch 3) dated May 29, 1981.
The exemption requested was that a radiograph not be performed on a
repaired arc strike due to geometry of the repair.
lne line involved is
a 2" shutdown cooling / low pressure safety injection crosstie line.
No
unaccepteble conditions were identified.
(0 pen) Unresolved item (317/81-04-01; 318/81-04-05) 10 CFR 50.72
Reporting Requirements. The inspector informed the licensee that the NRC
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would enforce a threshold of 25*. of the Technical Specification limits
with respect to reporting unplanned or uncontrolled releases of
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radioactive material) (Item a.8)
This item remains open pending
revision of CCI 11bD to resolve remaining differences between the NRC and
licensee's proceaure, as described in Inspection Report 317/81-09;
318/81-09.
(Closed) Unresolved Item (317/80-08-04) AFW Suction Pressure Alarm Masked
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During Idle Conditions by a Low Discharge Pressure Common Alarm. Alarm
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windows C-47 on Units 1 and 2 have been modified to annunciate on low
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suction pressure only. The AFWS at Calvert Cliffs requires manual
operator action to maintain steam generator levels. A pump discharge
pressure indication is provided in the Control Room, as are flow rates to
both steam generators.
(Closed) Unresolved Item (317/79-11-03) Provide Personnel Frisking
Capabilities at Exit from RWT Rooms.
The licensee has installed lead
shielded booths at the exits from both Units' RWT Rooms. The inspector
noted that backgrouno levels within the booth, allow adequate frisking by
shielding from the RWT.
3.
Review of Plant Oge_ rations
a.
Plant Tour
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At various times the inspector toured the facility, including the
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Control Room, Auxiitary o ilding (all levels, no High Radistion
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Areas), TLrtino Building, Outside Periphercl Area, Security
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Buildings, Health Physics Control Points, Diesel Generator Rooms,
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Service Building and Intake Structure.
b.
Instrumentation
Control room proces; instruments were observed for correlation
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between channels and for conformance with Technical Specification
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requirements.
c.
Annunciator Alarms
The inspector observed various alarm conditions which had been
received and acknowledged.
These conditions were discussed with
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shift personnel who were knowledgehole of the alarms and actions
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required. During plant inspections, the inspector observed the
condition of equipment associated with various alarms.
d.
5_hift Manning
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The operating shifts were observed to be staffed to meet the
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operating requirements of Technical Specifications, Section 6, both
to the number and type of licenses.
Control room and shift manning
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was observed to be in conformance with Technical Specifications and
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site administrative procedures.
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e.
Radiation Protection Controls
Radiation protection control areas were inspected.
Radfation Work
Permits in use were reviewed, and compliance with those documents,
as to protective clothing and required nonitoring instrurents, was
inspected.
Proper posting of radiation cnd high radiation areas was
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reviewed in addition to verifying requirements for wearing of
appropriate personal monitoring devices.
f.
Plant Housekeeping Controls
Storage of matarials and components was observed with respect to
prevention of fire and safety hazards.
Plant housekeeping was
evaluated with respect to controlling the spread of surface and
airborne contamination,
g.
Fire Protection / Prevention
The inspector examined the condition of selected pieces of fire
fighting equipment. Combustible materials were being controlled and
were not found near vital areas.
Selected cable penetrations were
examined and fire barriers were found intact.
Cable trays were
clear of debris.
h.
Control of Equipment
During plant inspections, selected equipmert under safety tag
control was examined.
Equipment conditions were consistent with
information in plant control logs.
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Instrument Channels
Instrument channel checks recorded on routine logs were reviewed.
An independent comparison was made of selected instruments.
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Equipment Lineups
The inspector examined the breaker position on switchgear and motor
control centers in accessible portions of the plant.
Equipment
conditions, including valve lineups. were reviewed for conformance
with Tecnnical Specif7 cations and operating requirements.
k.
Review of Operating Logs, Records
Logs and records were reviewed to identify significant changes and
trenos, to assure required entries were being made, to verify
Operating Ordere conform to the Technical Specifications, to verify
proper identification of abnormal conditions, and to verify
conformance to reporting requirements and Limiting Conditions for
Operation.
The following records were reviewed for the report
period:
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Shift Supervisor's Log
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Unit 1 Control Room Operator's Log
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Unit 2 Contrcl Room Operator's Log
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Nuclear Plant Engineer - Operations Notes and
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Instructicns
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Unit 1 and 2's Control Room Daily Operating Logs
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(sampling review).
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(1) Findings
At 3:30 p.m. on June 12, 1981, while conducting a routine plant
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inspection, the inspector discovered 1-LS-4142-C (refueling
water tank low to RAS) isolated.
1-LS-4142-C provides a signal
to Engineering Safety Features Actuation System (ESFAS) Channel
"C" to switch the emergency core cooling system from the
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injection mode to the recirculation mode.
Upon discovery,
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Instrument & Control personnel verified the level switch
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operable by performing the applicable portion of Surveillance
Test STP-M-220-1.
The level switch was returned to service at
6:25 p.m.
The three (3) redundant level switches remained
operable throughout the event.
The cause of the isolation was apparently of failure of an I&C
technician to restore the level switch to service follow (ng
completion of Monthly Suryr-i!;ance Test STP-M-220-1 on May 26, 1981.
To prevent ricurrence, the licensee revised the Surveillance Test
Procedure (R(vision 3, approved June 24, 1981) to describe
specifically the inservice valve lineup and to provide signature
bl:n!= #e- =cknowledging each switch's return to service. The
inspector reviewed the licensee's corrective actions including the
revised procedure and concluded that the licensee had taken and
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completed adequate corrective actions prior to completion of the
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inspection period. The inspector stated that failure to restore
Level Switch 1-LS-4142-C to service following testing was an item of
noncompliance (50-317/81-13-01).
4.
Plant Maintenance
During the inspection period, the inspector observed various maintenance
and problem investigation activities.
The inspector reviewed these
activities to verify compliance with regulatory requirements, including
those stated in the Technical Specifications; compliance with the
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administrative and maintenance procedures; compliance with applicable
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codes and standards; required QA/QC involvement; proper use of safety
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tags; proper equipment alignment and use of jumpers; personnel
qualifications; radiological controls for worker protection; retest
requirements and ascertain reportability as required by Technical
Specifications. The following act;vities were included during this
review:
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MR IM-81-2086, Replace Faulty Trip Unit, TM/LP Channel A, observed
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6/9/81.
PMS 2-58-I-Q-2, Steam Generator Pressure Loops; Cleaning Resistor
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Connections, observed 6/9/81.
MR 0-81-2621, 12 MSIV 13 Second Shutting Time, observed 6/15/81.
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MR 0-81-2762, 1 MOV 5233 Broke in Two (12 A Waterbox Inlet
Circulating Water Valve, NSR), observed on 6/22/81.
1-19A-M-SA-1 and 1-19A-M-A-1, Instrument Air Compressor Preventive
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Maintenance (NSR) observed work on 12 I/A compressor on 6/30/81.
During shutdown testing on Unit 1 on 7/14/81 No. 12 MSIV was discovered
to have a slow closure time (13 seconds versus required 3.6 seconds).
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The inspector observed part of the maintenance actions to correct the
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slow closure.
Following replacement of a hydraulic accumulator bladder
and additional stroke testing, the MSIV timing was discovered to be 2.7
seconds. By licensee procedure the required clo;ure time was 3.4 1 2
seconds. The inspector went to the Unit 1 MSIV Room on 7/15 to observe
timing adjustment. The mechanics and QC inspector n rforming and
observing the adjustments were unsure when asked initially which was No.
12 MSIV, however, indicated that both valves needed adjustment.
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inspector checked with the Control Room and discovered that no work was
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authorized on 11 MSIV but that both orifice valves were required to be
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adjusted on 12 MSIV. An apparent communications breakdown had occurred
in that the mechani::s understood that both MSIVs required adjustment.
The restriction orifice adj"c+m=+ '-m
m . = =: to its original position
under post written MR M-81-234 issued to doct. ment work on 6/18/81.
Correct adjustment of 12 MSIV was accomplished.
The licensee committed
to verify 2 times a week the partial stroke time of 12 MSIV stating that
the slow closure probably would be detected by a degradation of partial
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stroke time. The licensee discussed past failure history of 12 MSIV and
noted that only one additional failure (May, 1981) had occurred in the
last two years of quarterly testing. The inspector stated that MSIV slow
closure times would be followed by the NRC (317/81-13-02).
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The inspector also stated that performing work on 11 MSIV when not
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authorized by a Maintenance Request was an item of noncompliance
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(317/81-13-03).
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5.
Surveillance Testing
The inspector observed portions of the following surveillance (or other)
testing. The inspector verified that testing was performed in accordance
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with approved procedures, limiting conditions for operation were
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satisfir3, test results (if completed at time of observation) were
satisfactory, removal and restoration of equipment were accomplished and
that defici'encies identified were properly reviewed and resolved.
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The following tests were included in this review.
STP M-220-2, ESFAS Functional Test, observed on 6/23/81
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STP M-210 B-2, RPS Functional Tests, observed on 6/9/81
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ETS Sampling, 10 minutes Unit 2 Travelling Screen Washing Count,
observed on C/8/81
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Daily Nuclear Instrument Calibration, observed on Unit 1 on 6/18/81
No unacceptable conditions were identified.
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6.
Review of Events Requiring One Hour Notification to the NRC
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a.
Pressurizer Level Devietions
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On 6/1/81 during a Unit 1 restart after a weekend outage to
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repair a RCP lube oil leak, manual control of steam generator
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water level at low power resulted in repeated oscillations. Such
deviaticns , caused by temperature variations from steam
ganerator level or turbine loading changes, are re: tine during
st.artups and shutdowns.
The licensee attempted to stabilize
conditions prior to incremental load increases, and shifted to
staSle, automatic control when a sufficient steamirg rate was
reached.
The event was reported to the Operations Center as
required by 10 CFR 50.72.a(5).
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At 6:25 a.m. on 6/26/81 Unit 1 Pressurizer Level Program was
discovered drifted outside tolerance allowed by T.S. (216"
versus 210" allowed).
The level was returned in. band within 10
minutes.
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Pressurizer Level (Unit 1) was out of bar.d it.: mediately prior to
the U" t 1 trip caused by a partial loss of instrument air (see
belos) on 6/30/81.
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Unit 2 Pressurizer Level was out of band between 3:00 p.m.
until 4:25 p.m. on 7/3/81 due to a gradual pressurizer level
decrease while the chargirg pumps were turned off to make a
surface repair to a common discharge header test connection
leak.
The level went from 220" (top of program) to 165"
Charging flow was restored r 4:08 p.m.
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Unit 2 Pressurizar [ ,el was out of band at 2:20 p.m. on 7/4
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during restart osc ilations fol' awing a unit trip on 7/4/81.
The licensee stated that the new T.S. were overly restrictive in
specifying a 5's level error froia program to consider the pressurizer
inoperable and additionally did not contain a window of time to
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allow operation outside the band as was the case with other
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Technical Specifications, such as the DNB carameters.
They further
stated that they were pursuing a wider band with the vendar (CE) and
would equest a T.S. change to allow operational flexibility.
Resolution of the pressurizer level Limiting Condition for Operation
is an unresolved item (317/81-13-04; 318/81-13-01).
b.
Unit I tripped about 8:00 a.m., 6/30 due to low No. 11 Steam
Generator water level.
The trarsient cccurred while valving out a
portion of the instrumert a;r (IA) system.
Partial loss of IA
pressure caused feed water to rapidly increase. Operator action to
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reduce flow, coupled with control system respor.se upon restoration
of IA pressure, resultte in the low level condition.
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The cause of loss of instrument air pressure was not conclusisely
found. The operator involved stated a correct isolation lineup had
been performed (bypass valve on air dryer tcwers opened before
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isolations closed). A partial loss of instrument air occurred later
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in the cay on Unit 1 duo to botn towers oeing steck in the
regenerztion cycle.
The towers were quickly bypassed to restore air
pressure.
Four instrument air valves and solenoid valve were
reworke
to correct the tc.er problem.
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Unit 2 tripped at 04:21 a.m. on 7/4. The t-ip was caused by Turbine
Vacuum trip testing.
This testing lowers Auto Step Oil Pressure
about 10 psid. Auto Stop Oil Prassure was found to be low following
the trip and was adjusted above 100 psig.
The licensee plans to
change testing procedures te verify adequate Auto Stop Oil Pressure
prior to testing the Turbine Vacuum trip.
d.
At 06:35 a.m. on 7/4 a licensee employee was transported to Calvert
Memorial Hospital to investigate a back pain.
The employee had
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strained his back during a containment entry following the Unit 2
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plant trip.
The individual was not contaminated.
e.
At about 8:30 p.m. on 6/13, increasing Unit 1 RCS leakage was
noticed.
Initial checks identified about 9.1 gpm. A detailed
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check completed at 9:45 p.ni. Indicated that (identified) leakage had
increased to 16 gpm. A controlled shutdown was initiated as
required by the lechnical Specifications (10 gpm limit).
The NRC
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Operations Center was notified about 10:30 p.m. of the required
shutdown due to RCS leakage.
About 0015 a.m., prior to changing
from Mode 1 to Mode 2, an unusual event was declared per the Site
Emergency Plan and the required State and local officials were
notified. The leak was found to be blown packing on an isolation
valve from the 12A Reactor Coolant Pump differential pressure
transmitter.
The leakage was stopped and back in specification
about 11:00 a.m. on 6/14/81. Although no new information was
available at OU15, an unusual event was declared. The Site
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Emergency Plan requires NRC notification but the associated
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checklist does not have a time block for this specific action. To
prevent confusion in future events the licenses stated that the Site
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Emergency Plan Implementing Procedures would be revised to
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specifically require documentation of NRC notification during any
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emergency condition
Revisica of ERPIP 4.2 Follow-up Communications
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Checklist will be followed (317/81-13-05).
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7.
IE Circular Review
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The following IE Circulars were reviewed on site to determine that the
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circular was received by licensee management, that a review for
applicability was per.'ormed, and that further action taken or planned was
appropriate.
80-15 Loss of Reactor Coolant Pump Cooling and Natural Circulation
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Cocldown. The licensee has routed this circular to all operators
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and included the event in the requalification lecture series.
The
Plant Operational Experience Assessment Committee has reviewed
various aspects of this event and recommended actions.
The licensee
is participating with the CE Owners Group in the development of
revised natural circulation coolaown and shutdown cooling
procedures.
NRR is also following licensee actions in this area
(Generic letter 81-21).
Circular 80-15 is considered closed.
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Additional licensec actions / reviews in this area will be inspected
following up on Circular 81-10, Steam Voiding in the Reactor Coolant
System, issued July 2, 1981.
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80-05 Emergency Diesel Generator Lubricating 011 Addition and Onsite
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Supply. The licensee had received and reviewed this circular and
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taken appropriate action.
Lubricacing oil must be added directly to
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the storage tank in the Diesel Rooms for Calvert Cliff's EDGs. The
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oil must be added directly from a barrel with a portable, air driven
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pump. A sign is in place by the tank stating the type of oil
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required.
The licensee reviewed oil consumption records and made
arrangements to have onsite stores increased to include maxium usage
for the T.S. Fuel Oil supply time requ'reaent.
8.
Review of Licensee Evant Reports LLER_s.)
a.
The inspector reviewed LERs submitted to the NRC:RI office to verify
that the details of the event were clearly reported, including the
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accuracy of the description of cause and adequacy of corrective
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action.
The inspector determined whether further information was
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required from the licensee, whether generic implications were
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indicated, and whether the event warranted cnsite followup.
The
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following LERs wera reviewed:
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LE R No
Date of Event
Date of Report
Sub.iect
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UNIT 1
81-26/3L"
05/27/81
06/10/81
ACOUSTIC FLOW INDICATOR
FOR PRESSURIZER SAFETY VALVE
INOPERABLE (Note 1)
81-34/3L
05/08/81
06/01/81
- 11 EDG FAILED 10 REACH RATED
SPEED IN LESS THAN 10 SECONDS
81-35/JL'
05/06/81
06/05/81
- 18 CELL OF VDC BATTERY f12
FAILED (Note 1)
2
81-36/3a.
05/15/81
06/15/81
DURING SU.iVEsLLANCE TEST #12
EDG UPPER CRANKSilAFT THRUST
BEARING FOUND EXCESSIVELY WORN
81-37/3L
05/21/81
06/17/81
INCORE DETECTORS INOPERABLE
81-38/41
05/26/81
06/09/81
PAY WATER SAMPLE SHOWED 1549 ~+
pCi/1 AT PLANT FALLOUT AREA
81-40/3L*
06/01/81
06/i6/31
FRESSURIZER LEVEL DEVIATED BY
F10RE THAN +/-5% DURING CHANGES
IN RCS TEMPERATURE (Note .")
81-41/3L*
06/12/81
06/15/61
REFUELING !!ATER TANK LEVEL SWITCH
ISOLATED (Noto 3)
81-42/1T*
06/1?/81
06/26/8!
IMPROPER PIPE SIZING OF RCS CODE
SAFETY VALVES
d!ll T 2
81-28/1T*
06/13/81
06/26/81
IMPROPER PIPE SIZING OF RCS
CODE SAFETY VALVES
Note 1 - Addressed in Inspection Report 317/81-11.
flute 2 - Addressed in pa rag raph 6.
Note 3 - Addressed in pa rag raph 3.
- Donotet LERs followed up onsite.
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b.
For the LERs selected for onsite review (denoted by asterisks
above), the inspector verified that appropriate corrective action
was taken or responsibility assignad 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.
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81-42 (Unit 1) & 81-28 (Unit 2) Improper Pipe Size of RCS Code
Safety Valves.
Ti.e licensee was informed by Combustion
Engineering that the pressurizer safety valves (Dessser
supplied) had been analyzed for flow with a 2.5 inch inside
diameter supply spool piece. The piping installed is scheduled
160 pipe with an inside diameter of 2.125 inches less than 2
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feet in length.
The vendor states that supply piping had been
analyzed with a safety factor of two so that the piping ID
reduction should not result in excessive restriction.
Further
review indicated that the restriction would result in a flow
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reduction betwoen 1 to 2%. The licensee stated in LER 81-42:
" Parametric contingency analyses recently performed in
support of the EPRI Safety ani Relief Valve Test Program
(EPRI Project V102-20) have demonstrated a large margin in
the sizi.ig of the pressurizer safety valves for Calvert
Cliffs.
Based on the licensing methods for these plants,
the calculated required safety valve capacity is more than
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an order of magnitude below that specified for the plant.
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It is unlikely that the reduced valve capacity resulting
from the smaller inlet piping could have a significant
impact in light of this large design margin.
Therefore,
it is concluded that the above described reduction in
inlet pipe diameter for the Dresser Modci 31739A Safety
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Valve does not constitute a safety hazard for Calvert
Cliffs Units 1 and 2."
Although a safety hazard does not appear to exist the NRC will
perform further revie.<s of the EPRI Safety and Relief Valve
program and the effecte of a reduced size inlet pipe.
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81-42 (Unit 1) and 81-28 (Unit 2) remain open pending further
NRC review.
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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.
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a.
Physical Protection Security Organizition
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Observations and personnel interviews indicated that a full
time member of the security organization with authority to
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direct physical security actions was present, as required.
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Manning of all three shifts on various days was observed to be
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as required.
b.
Physical Barriers
Selected barriers in the protected area (PA) and the vital areas
(VA) were observed and random monitoring of isolation zones was
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performed. Observations of truck and car searches vere made.
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c.
Access Control
Observations of the following items were made:
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Identification, authorization and badging
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Arcess control searches
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Escorting
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Communications
Compensatory measures when required.
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No unacceptable conditions were identified.
10.
Radioacti/e Waste Releases
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Records and sample results of the following liquid and/or gaseous
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radioactive wasta releases were reviewed to verify conformance with
regulatory requirements prior to release.
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Liquid Release Permit M-064-81, Miscellaneous Waste Mor.itor Tank
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released on 6/18/81, Total curies 1.265x10 '.
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Liquid Release Permit R-048-21, 12 Reactor Coolant Waste Monitor
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Tank released on 6/22/81 (Not entered on Computer Histcry as of
6/23/81).
Gaseous Release Permit G-026-81, Waste Gas Decay Tank 13, isolated
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5/23/81, released 6/1/81.
Estimated 5.5x10' m '/sec (Group I)
release rate (calculations on final release rate not performed as of
6/24/81).
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Unit 2 Condenser Off Gas Grab Samples (Installed RMS monitor
Date
Time
File Name
Results
6/10/81
1310
F42003
None detected
6/09/81
1000
F42002
None detected
6/08/81
1408
UP F42005
None detected
6/05/81
0830
U2 F42C03
None detected
6/04/81
0730
U2 F42002
None detected
The inspector questioned t'ie long time to complete the calculations for
the release of Waste Gas Decay Tank 13 and provisions for entry of liquid
releases into the computer history. These items will be followed by the
inspector (317/81-13-06; 318/81-13-02).
11.
Licensee Action on NUREG 0660, NRC Action Plan Developed as a
?esult of the TMI-2 Accident
The NRC's Office of Inspection and Enforcement has been assigned
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inspection responsibility for licensee implementation of selected action
plan items.
These items have been further broken down into 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 censiderable inspector judgement.
The
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following action plan items were reviewed during this inspection (number
of description in parenthesis).
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I.C.6
'!erify Performance of Oparating Activities.
This item was
previously inspected and remains open (Combined Inspection Reports
317/81-02; 318/81-02 and 317/81-11; 318/81-11).
During this
inspection the licensee committed to implement the following
additional actions to comply with I.C.6.
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a.
By Septenber 1, 1981 a second independent verification by a
qualified operator will be performed when equipment is removed from
service in accordance with CLi 112 " Safety Tagging". A second
independent verification will also be performed when equipment is
returned to service.
In each case the second verification may be
waived if proper system lineup is verified by functional oest or if
such verification would necessitate entry into a high radiation
area.
b.
A second verification will not be required when equipment it removed
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for service for the purpose of conducting surveillance testing.
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However, by October 1, 1981 a second independent verification by a
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qualified operator will be performed when equipment is returned to
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service upon ccmpletion of surveillance testing.
This second
verification may be waived if such verification would necessitate
entry irto high radiation area, if proper system lineup is verified
by functional testino, or if the component to be verified receives a
safety signal which was not defeated by the surveillance test
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procedure.
c.
A computerized system for tracking outstanding maintenance requests
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will be operational by July 1, 1982.
In the interim period
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Operations personnel will continue to keep track of outstanding
maintenance actions by wti of infor.ual turnover sheets and by
logging all effective teco spec action statements in the Control
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Room Operator log.
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d.
Prior to restart from the next refueling outage valve checklists and
procedures for their use will be developed for all instrument root
valves in safety related systems.
The inspector stated that the above proposed actions, coupled with the
licensee's existing programs and status monitoring equipment adequately
implement the guidance of TAP I.C.6.
The line item will remain upen
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pending implementation of the above actions and inspection by the NRC.
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12. Review of Periodic and Specir' 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
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report incluces the information required to be reported by NRC
requirements; test results and/or supporting information are consistent
with design predictions and pe.'formance specifications; planned
corrective action is adequata for resolutten of identified problems;
deters; nation whether any ir. formation in the report should be classified
as an abnormal occurrence; and the validity of reported information.
Within the scope of the above, the following periodic reports were
reviewed by the inspector:
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May,1981 Operations Status Reports for Calvert Cliffs No.1 Unit
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and Calvert Cliffs No. 2 Unit, dated June 12, 1981.
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13. Unresolved Items
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Unresolved items are matters about which more information is required to
determine whether they are acceptable, items of nonconipliance or
deviations. An unresolved item addressed during this inspection is
discussed in Paragraph 6 of this report.
14.
Exit Interview
Meetings were held with senter facility management periodically during
the course of this inspection to discuss the inspection scope and
findings. A summary of inspection findings was also provided to the
licensee at the conclusion of the report period.
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