ML20054F756
| ML20054F756 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 05/18/1982 |
| From: | Architzel R, Mccabe E, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20054F731 | List: |
| References | |
| 50-317-82-07, 50-317-82-7, 50-318-82-07, 50-318-82-7, NUDOCS 8206170290 | |
| Download: ML20054F756 (20) | |
See also: IR 05000317/1982007
Text
DCS 50317 820417
020421
50318 820417
50320 790328
820314
820504
820320
820319
820429
820402
820321
820503
820407
The report details
820316
820328
contain Safeguards Info l
820407
(Page 6 only)
820401
i
U. S. NUCLEAR REGULATORY COMMISSION
THE INFORMATION ON THIS
Region I
PAGE IS DEEMED TO BE
APPROPRIATE FOR PUBLIC
50-317/82-07
DISCLOSURE PURSUANT TO
Report No.
50-318/82-07
50-317
Docket No.
50-318
C
License No. DPR-69
Priority
--
Category
C
Licensee:
Baltimore Gas and Electric Company
P. O. Box 1475
Baltimore, Maryland 21203
Facility Name: Calvert Cliffs Nuclear Power Plant, Units 1 and 2
Inspection At: Lusby, Maryland
Inspection Conducted: April 13 - May 11,1982
Inspectors:
5~
Z
R~. E. Architze), Senior' Resident Reactor Inspector
date signed
ll
Y 07
b 7s
D.
C~. Trimble, Resid'ent Reactor Inspector
date signed
Approved By:
CO
5'/IB / Tr?.
i
E. C. McCabe, Jr. , Chief, Reactor Projects
date signed
Section 2B
Inspection Sumary:
Inspection on 4/13 - 5/11/82 (Combined Report Nos. 50-317/82-07and50-318/82-07).
Areas Inspected: Routine, onsite regular and backshift inspection by the resident
inspector (119 hours0.00138 days <br />0.0331 hours <br />1.967593e-4 weeks <br />4.52795e-5 months <br />). Areas inspected include 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 operations; main-
tenance; radioactive waste releases; open items; TMI Action Plan Items; Containment
Leakage Test requirements; and reports to the NRC.
Violations: Three: Failure to follow requirements for tagouts (detail 9.c), failure
to have operable hydrogen analyzer during Cycle 5 (deta.1 ll.c), and containment
leakage rate greater than allowed (detail 1 ,
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_ DETAILS
1.
Persons Contacted
The following technical and supervisory level personnel were c
entacted:
J. T. Carroll, Ganeral Supervisor, OperationsM. E. Bo
R. E. Denton, General Supervisor, Training / Technical Services
C. L. Dunkerl
W. S. Gibson,y, Shift Supervisor
J. E. Gilbert, Shift SupervisorGeneral Supervisor, Electrical & Controls
A. M. Hetrick, Radiation Safety Enginee,-R. P. Heibel, P
J. R. Hill, shift Supervisor
L. S. Hinkle, Engineering halyst
Electrical & Control Section
J. Lenhart, Radiological Support SupervisorD. W. Latha
e y Unit
J. F. Lohr, Shift Supervisor
G. S. Pavis, Engineer, OperationsR. G. Mathews, Assistant G
J. E. Rivera, Shift Supervisor
L. B. Russell
R. B. Sydnor,,EngineerPlant Superintendent
Electrical & Controls
D. Zyriek, Shift SupervisorJ. A. Tiernan, Manager,, Nuclear Power
Other licensee employees were also contacted.
2.
Licensee Action on Previous Inspection Findings
Yellow Dots on Control Boards or Remove.(Clo
_
y Placement of
inspector verified that the yellow dots have been removed fDuring Control
rom Control Boards.
The NRC Performance Appraisal Secticn (PAS) report on Calvert C
318/82-01),
section 3.a.(8) dated April 14, 1982 noted that auditor indepen
s (317/82-01,
was conducted of the Off Site Safety Review Comm
QA was also the Chairman of the OSSRC.
eManager),
. . . .a
completed 5/13/81.
The subject audit was #81-0SSRC-1
individual replaced the Manager, QA as OSSRC Chaiman la
Also, reports of comencement and completion (with summary findi
a endar year 1981
requested audit were addressed directly to the Vice President
ngs) of the CSSRC
to the OSSRC Chairman wi ch somewhat removed the lead
, Supply, as opposed
direct management reporting chain.
r from his normal
Manual to ANS
which states that "While perfoming theThe licensee is
3.2-1976
auditors) shall not report to a management representative who has
audit, they (the
responsibility for the activity being audited."
e
auditor, at the request of the individual who was and
e lead
pervisor
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3
throughout the audit period, audited activities for which his supervisor was
i
responsible. True auditor independence was not maintained. The inspector
reviewed this issue with the Manager, QA on 4/30/82 who stated that various
alternatives would be evaluated and long-term corrective action taken to ensure
that auditor independence is maintained in future audits of OSSRC activities.
This item is unresolved pending licensee action and subsequent NRC:RI review
(317/82-07-01,318/82-07-01).
The NRC PAS report also pointed out licensee weaknesses in the quality of
written safety evaluations (SE) for facility design changes accomplished
pursuant to 10CFR50.59.
It stated that SE's for numerous Facility Change
Requests (FCR) had been reviewed and quoted the SE's for FCR's 79-1024 on
the halon system and 81-1011 on fire barrier modifications.
It pointed out
the following observations associated with SE's:
Failure to provide "the bases for detemination that the change
--
does not involve an unreviewed safety question";
"nothing more than simple statements of conclusion providing no
--
bases for the detemination"; and
-- " required the reviewer to accept the evaluation on the assumption
that proper installation would resolve any concerns".
The inspector reviewed the SE's for the FCR's referenced in the PAS report and
three additional FCR's (80-1027 on the halon system, 80-1017 on the replacement
of solenoid valves, and 79-1055 onESFASresetmodifications).
One of the three additional FCR's reviewed (80-1027) exhibited the problems
discussed in the PAS report. The SE's for FCR's 79-1024 and 80-1027 stated
only that "Halon systems are not required to be safety related or function
in a seismic event. However, the systems are seisrically supported to preclude
the possibility of falling on safety related equip.nent". The SE for FCR 81-
1011 stated only that "Ductwork will be purchased and installed SR (safety
related) and will be seismically supported.
Barriers are seismically designed
and installed safety related.
Barriers will close up openings between existing
structure and will be seismically designed and installed safety related".
10CFR50.59(b) requires that records of changes to a facility as described in
the Safety Analysis Report (SAR) be maintained which include written SE's
providing the bases for detemination that the changes do not involve unreviewed
safety questions (USQ), A USQ is involved if the probability or consequences of
an accident or malfunction of equipment important to safety previously evaluated
it, the SAR may be increased, or the possibility for an accident or malfunction
of a different type than any previously evaluated in the SAR may be created, or
if the margin of safety as defined in the bases for any Technical Specification
is reduced. The SE's for FCR's 80-1027, 79-1024, and 81-1011 do not provide
sufficient bases infomation to adequately support their conclusions that no
USQs existed in that they were not sufficiently detailed in their discussions of
FCR and applicable SAR design criteria to make any meaningful comparisons. They
did not sufficiently describe what accidents or malfunctions (if any) were
addressed in the SAR or what items were considered in reaching the conclusion
that the changes did not increase the probabilities of SAR described accidents
or malfunctions or introduce accidents or malfunctions different than those
evaluated in the SAR.
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4
The inspector determined that the above examples of 10CFR50.59 Safety
Evaluations were indicative of historical lack of depth of the Safety
Evaluations, confirming the validity of the findin
mance Appraisal Team (Report 317/82-01, 318/82-01)gs of the NRC's Perfor-
and Inspection Report
317/82-05, 318/82-05 (failure to evaluate certain aspects of a facility
change). The NRC will closely follow the licensee's corrective actions in
this area, which are required to be detailed in writing bv the licensee in
response to the referenced inspection reports (317/82-0) ')2, 318/82-07-02).
3.
Review of Events Requiring One Hour Notification to the NRC
The circumstances surrounding the following event requiring prompt NRC (one
hour) notification via the dedicated telephone (ENS-line) was reviewed.
At 7.39 a.m. on 4/17/82 a technician attempting to post a tagout on
--
the Unit 1 Control Element Drive System (CEDM) mistakenly op(ened the
breaker supplying power to Unit 2 Control Element Assembly CEA) 21
causing it to drop into the reactor core. At 7:41 a.m. CEA 20 dropped
when the same technician opened its supply breaker. The shift super-
visor, after failing to establish communications with the technician,
in anticipation of additional CEA drops ordered that Unit 2 be manually
tripped.
(Unit 1 had been shutdown earlier that day for a refueling
outage.) Prior to the Unit 2 trip, pressurizer levei fell 30 inches
below its program value. The licensee notified the NRC Operations
Center by ENS at 8:11 a.m.
Safety systems functioned as designed
following the trip.
4.
Radioactive Waste Releases
Records and sample results of the following liquid and/or gaseous radioactive
waste releases were reviewed to verify conformance with regulatory requirements
prior to release.
Gaseous Waste Permit G-039-82, Unit 1 Containment Modified Purge,
--
released on 4/18/82. Group I release rate 1.46 x 105 m3/sec.,
Group II release rate 1.25 x 102 m3/sec.
Release of Reactor Coolang Waste Monitor Tank 12 on 4/11/82.
--
Total released 4.51 x 10- curies, excluding tritium and noble
gases.
Liquid Waste Release Pennit R-033-82,12 RCWMT released 5/6/82.
--
Expected curies released 2.99 E-2 (pre-release results).
Containment Release Permit G-049-82, Unit 2 Vent via ECCS Pump
--
3
Room on 5/6/82. Group I rglease rate 8.81 E+2 m /sec., Group
II release rate 5.37 E-2 m3/sec.
No unacceptable conditions were identified.
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5.
Plant Maintenance
The inspector observed and reviewed maintenance and problem investigation
activities to verify compliance with regulations, administrative and
maintenance procedures, and codes and standards, proper QA/QC involvement,
safety tags use, equipment alignment, jumpers use, personnel qualifications,
radiological controls for worker protection, fire protection, retest require-
ments, and reportability per Technical Specifications. The following
activities were included.
Troubleshooting of Unit 2 CEDM 38 after rod drop on 4/17/82.
--
MR-82-8194, Modification to Electrical Penetration (FCR-79-65)
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45 foot elevation, west penetration on 4/20/82.
MR-82-8016, Steam Generator 12 Support Plate Rim Cut, implemer. ting
--
Maintenance Procedure SG-14 (approved 4/19/82) observed 4/26/82.
No unacceptable conditions were identified.
6.
General Orientation Retraining
The inspector ai. tended General Employee Orientation Retraining, Part I (facility
access) and Part II (radiation protection) on April 15, 1982. The training was
comprehensive in nature and in accordance with the lesson plan. The examination
for Part II training was prepared by the Institute of Nuclear Power Operations
as part of a pilot program to develop generic radiation protection retraining.
The inspector noted that the examination appeared to be comprehensive and was
more difficult than historical exams for Part II training. The instructor
commented that a higher failure rate was being experienced on the newer
examination (about 30%) requiring more instensive retraining for selected
individuals.
No unacceptable conditions were identified.
7.
Observation of Physical Security
the inspector checked, during regular and off-shift hours, on whether selected
aspects of security met regulatory requirements, physical security plans, and
approved procedures,
a.
Security Staffing
01servations and personnel interviews indicated that a full time
--
trember 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 required.
b.
Physical Barriers
Selected barriers in the protected area (PA) and the vital area (VA) were
observed.
Random monitoring of isolation zones was performed. Observa-
tions of truck and car searches were made. One finding relating to the
protected area barrier is addressed on the following page.
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c.
Access Control
Observations of the following were made:
Identification, authorization, and badging;
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Access control searchts;
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Escorting;
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Communications;
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Compensatory measures when required.
--
d.
Bomb Threat
One bomb threat was received during this reporting period. The
required security procedures were followed. Appropriate searches
were conducted with negative results.
e.
Potential Strike
During this inspection period the licensee made preparations to cope
with a threatened local union picket line of pipe insulators against
an onsite subcontractor. The picket line, anticipated to begin about
4/19/82 was never established. The inspector reviewed the licensee's
preparations and arrangements for coping with the picket line.
No unacceptable conditions were identified.
8.
Licensee Action on NUREG 0660, NRC Action Plan Developed as ~a Result of the
TMI-2 Accident
The NRC's Region I Office has inspection responsibility for selected action
plan items. These items have been broken down into numbered descri
(enclosure 1 to NUREG 0737, Clarification of TMI Action Plan Items)ptions
Licensee
.
letters containing commitments to the NRC were used as the basis for accept-
ability, along with NRC clarification letters and inspector judgment. The
following items were reviewed.
I.C.6, Verify Correct Performance of Operating Activities. This item
--
had previously been inspected and remains open pending implementation
of licensee commitments.
During the review of the tagging associated
with a Unit 2 CEDM drop and reactor trip on 4/17/82, the inspector
noted that independent verification was not required.
CCI 112C, Safety and Safety Tagging requires a second, independent
verification of correct implementation of equipment control measures
for the use of apparatus service tags, including return to service.
These are the principal tags in use at the site for both mechanical
and I&C maintenance work. For the use of low voltage permits (600
volts or lower) an independent verification is not required.
In
addition, the return to service position is not required to be
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specified or documented, just the lifting of the tags. For the use
of high voltage electrical equipment (greater than 600 volts) CCI ll2C
requires an independent verification of switch position by the job
supervisor and in addition, potential tests by electricians to verify
the equipment is deenergized. Documentation of these checks is not
required. The inspector noted that this methodology was not according
to the guidance of I.C.6 nor the licensee's comitments in their letter
dated December 15, 1980. The licensee stated that they were investigating
methods to implement independent verifications for High and Low Voltage
Permits. This item is unresolved (317/82-07-04, 318/82-07-04).
II.K.3.17, ECCS System Outages. The inspector reviewed the licensee's
--
second submittal supplying infomation on Emergency Core Cooling System
unavailability. The letter, dated April 13, 1982 was in response to an
NRC request to go beyond a listing based on LER's and include outages
due to surveillance testing, planned and unplanned, and preventive
maintenance.
The inspector noted that the licensee's submittal did not include all
preventive maintenance. As an example, removal of the Service Water and
Component Cooling Water Heat exchangers from service to mechanically clean
tubes was not included, however, the length of time these were out-of-
service for preventive maintenance had been the subject of a previous
unresolved item. The licensee acknowledged the inspector's coments and
stated that a review would be perfomed of the Calvert Cliffs preventive
maintenance program and revised outage infomation forwarded to the NRC
by May 28,1982. This item is unresolved (317/82-07-05, 318/82-07-05)
pending resubmission by the licensee and NRC review.
9.
Review of Plant Operations
a.
Daily Inspection
The inspector toured the facility to verify proper manning and access
control, and observed adherence to approved procedures and LCOs.
Instrumentation and recorder traces were observed. Status of control
room annunciators was reviewed. Nuclear instrument panels and other
reactor protective systems was examined.
Control rod insertion limits
were verified. Containment temperature and pressure indications were
checked against Technical Specifications. Stack monitor recorder traces
were reviewed for indications of releases.
Panel indications for on-
site /offsite emergency power sources were examined for automatic
operability. Control room, shift supervisor, tagout log books, and
operating orders were reviewed for operating trends and activities.
During egress from the protected area, the inspector verified operability
of radiological monitoring equipment and that radioactivity monitoring
was done before release of equipment and materials to unrestricted use.
These checks were performed on the following dates: April 15,17,19,
20, 21, 27, 29, 30, May 5, 6, 7, and 10,1982.
On 4/21/82 the inspector obserycd that Unit 1 shutdown cooling flow
--
was 2200 gallons per minute. The unit was in Mode 5 and drained
9
down to the top of the hot leg to facilitate getting water out of
the steam generator U-tubes. The Reactor Coolant System was being
borated to refueling concentration. The inspector questioned the
operator about the minimum requirement for shutdown cooling flow.
Technical Specifications for Modes 4 and 5 require that at least
2 coolant loops (of 4, including 2 shutdown cooling and 2 reactor
coolant) be operable and at least I be in operation.
(Undercer-
tain conditions all flow can be stopped for up to I hour.)
Technical Specifications for Reactor Coolant System flow requires
at least 3000 gallons per minute during any dilution of the reactor
coolant. Technical Specifications for refueling operations (Mode 6)
require at least I shutdown cooling loop be in operation at 3000
gallons per minute, however, this is allowed to be relaxed to 1500
gallons per minute if the water level is drained below the mid-plane
of the hot leg.
Because no dilution was in progress there was
apparently no specified requirement for flow. The inspector noted
that the conditions listed for reduced flow in Mode 6 were more
coninon occurrences in Mode 5, for example during replacement of
Reactor Coolant Pump seals and the evolutions in progress on 4/21/82.
The basis for the Technical Specifications included reasons for the
specified flow (Mode 6) to ensure sufficient cooling capacity, to
minimize the effects of a boron dilution incident and to prevent
boron statification. The inspector noted that these were valid
concerns in Mode 5 as well and stated that the licensee should
consider requesting an amendment to specify required Reactor Coolant
flow in Modes 4 and 5.
.'his item is unresolved (317/82-07-06)
and will be further reviewed by the NRC.
b.
Weekly System Alignment Inspection
Operating confirmation was made of selected piping system trains.
Accessible valve positions in the flow path were verified correct.
Proper power supply and breaker alignment was verified. Visual
inspections of major components were performed. Operability of
instruments essential to system perfonnance was verified. The fol-
lowing systems were checked.
Various system lineups in the Units 1 and 2 east and west 10
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foot Penetration Rooms on 4/16/82, including Service Water
lineup to Containment Coolers 12, 14, 22, and 24, Containment
Spray and Low Pressure Safety Injection Valves.
Low Pressure Safety Injection train 22 on 4/19/82.
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Unit 2 Component Cooling Water lineup in the Component Cooling
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Water and ECCS Pump Rooms on 4/27/82.
Containment Spray train 22 on 5/7/82.
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No unacceptable conditions were identified.
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c.
_ Biweekly Inspection
Verification of the following tagouts indicated the action wa
conducted.
s properly
Penetration, verified on 4/20/82.Tagout 19022, Loca
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on
Tagouc .9140, 21
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Charging Pump 011 Leak, verified on 4/30/82
Tank levels were also confimed. Boric acid tank samples
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cations.
During a review of the Unit 2 Tagout Book on 5/5/82 the ins
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noted that Service Water Pump 22 was listed as tagged i
pector
to lock position.
The tagout had been issued on 4/30/82 and
placed and independently verified on 5/1/82.
Pump 22 was neither in pull to lock nor tagged
Later, during a
restored to service on the same day the ta
Investigation
.
was on file in the Tagging Authority's Offic
A
.
Record did not document tag removal and restoration to n
,
up by either the initial or independent checkcr, required by
ne-
i
administrative procedures.
of Calvert Cliffs Instruction ll2C, safety and Safety Ta
regarding the clearing of tags and restoration of equipment to
service is a violation (318/82-07-06),
,
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d.
_0ther Checks
During plant tours, the inspector observed shift turnovers
pemits, protective clothing and respirators. practices at
, security
i
r
monitors were reviewed. status of personnel monitoring practici
Plant housekeeping and cleanliness was eval
with TS LCOs.
TS LCOs, including RCS Chemistry and Activity, Secondary Ch
Other
Activity, watertight doors, and remote instrumentation were ch
y and
e.
About 2:30 p.m. on 4/15/82, during an alignment of the Unit 1
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Refueling Water Tank (RWT) to the Spent Fuel Pool (SFP) p
cation system, approximately 2500 gallons of borated wate
fed through a malfunctioning 150 psi relief valve
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SFP cooler 11 to the miscellaneous waste receiver tank, 0-RV-1997
was quickly isolated and repaired on the followi
The valve
.
The
nvolved.
were posted beyond their expiration dates.On 4/19/8
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SWP No.
Expiration Date
82-286
4/13/82
82-284
4/13/82
82-173
4/14/82
82-176
4/14/82
This was pointed out to the on-duty principle radiation-chemistry
technician. The expired SWPs were removed by 4/20/82.
During a tour of the Unit 2 Charging Pump Room on 4/30/82 the
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inspector noted that the door to the enclosure for Charging Pump
22 had been blocked open. The enclosures had recently been
installed as part of the fire protection plant upgrade, however,
the door was not labeled as a fire door. The licensee stated that
the door in question was a fire door and that the Charging Pump
enclosure doors would be closed and appropriately labeled. This
item is unresolved (318/82-07-07) pending completion of the licensee's
actions and reinspection by the NRC.
About 9:30 a.m. on 4/20/82 a fire broke out on the second floor of a
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temporary 2-story building under construction east of the South
Service Building. The onsite fire brigade extinguished the fire
within 10 minutes. The local fire department responded within 15
minutes. No safety-related equipment or radioactive materials were
involved.
The inspector observed the actions of the onsite fire brigade and
security measures to allow rapid access for the local fire department
(SolomonsIsland). No unacceptable conditions were identified.
About 1:00 p.m. on 4/14/82 an approximately 1 inch layer of spent
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resin was found unifonnly spread over the top of a shipping cask liner,
contained by a 2 inch lip around the liner outside circumference.
The spillage occurred during a transfer operation of resin from
the spent resin metering tank at about 3:00 p.m. on 4/13/82. No
resin spread outside of the shipping cask. A small resin sample
measured 4 mrem /hr on contact. The liner top measured 400 mrem /hr
on contact. The outside of the cask measured 15 mrem /hr on contact.
No personnei exposure or contamination problems resulted.
Subsequent invetigation showed that about 150 cubic feet of resin
had been transfeired to the cask liner. The personnel involved
during the event hcd underestimated the amount of resin in the
holding tank and bei'eved they were only transferring about 90
cubic feet. There is a level indicator on the resin metering
tank.
Level is estimateo based on the number and volume of ion
exchangers flushed to the tank. The transfer operation had been
interrupted by a continuous air monitoring system (CAMS) alann at
3:00 p.m. which resulted in a 1 to 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> evacuation of the area.
A followup air sample showed zero MPC iodine and particulate
activity and the following gaseous activity.
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Isotope
~ Activity,uci/cc
Xe 131m
1.72 x 10-8
Xe 133
1.76 x 10-6
Xe 133m
1.72 x 10-8
Xe 135
4.9 x 10-11
The liner may have overfilled during the interruption. The inspector
discussed the event with radiation safety and operations personnel.
He expressed concern to the General Supervisor of Operations (GS0) on
4/20/82 that the exact cause needed to be identified and corrective
action taken to prevent recurrence. The GS0 stated that a radiation
safety engineer had been assigned to investicate the inchient to
determine appropriate corrective actions. This item is unresolved
pending licensee action to identify and correct associated problems
and subsequent NRC review (317/82-07-07).
10.
Containment Leakage Testing
During the week of March 8, 1982 the inspector discussed clarification of
10CFR50 Appendix J requirements with the licensee. A copy of an internal NRC
memorandum from the Director, Division of Systems Integration, NRR to the
Director, Division of Resident and Regional Inspection, I&E dated January 11,
1982 was handed to the licensee. The position of the memorandum was basically
that improvements in pathway leakages performed on paths testable in Type B
and C testing completed during the outage time preceeding a periodic integrated
containment leakage test must be added to the as found integrated results.
This would allow leakage information obtained fron the "as is" Type A (integrated)
test to be used to assess the containment condition and its integrity following
a period of plant operation. The licensee disagreed with the NRC position,
however, the inspector stated that this was the position which would be enforced.
On April 13, 1982 the licensee sent a letter to the Operating Reactors Project
Manager formally stating their disagreement with the NRC position in the
January 11, 1982 memorandum.
About 4/27/82 the inspector was informed by the licensee thet 9 penetrations,
including electrical (4) and piping (5) penetrations had been repaired or
removed on Unit 1 following the refueling shutdown which commenced on April 17,
1982 without testing for the "as found" leakage. The inspector held a meeting
with the licensee on April 28 to discuss this issue. The inspector expressed
concern that the licensee had decided to repair the penetrations without prior
testing. This decision had not been discussed with the NRC nor was the April 13,
1982 letter disagreeing with the NRC position distributed to the Resident
Inspector. The inspector informed the licensee that failure to make prior
measurements of pathway leakage meant that it was impossible to detemine
improvement for the purpose of calculating the "as found" integrated contain-
ment leakage and that the 1982 Integrated Test would be considered to be a
failure. The inspector also querted the licensee concerning whether any
additional repairs were anticipated prior to Type B and C testing. The licensee
stated that none were planned, but if any repairs were indicated they would test
for the "as found" condition.
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_ _ _ _ _ _ _ _ - . _ _ _ .
13
The licensee stated that a review could be made of the 9 repairs in question
in order to establish an upper boundary of leakage for those paths which had
1 valve or barrier still intact.
In addition, they stated that data was
available from the previous Type B and C tests which could be used as the basis
for improvement, notwithstanding any unquantified increase during Cycle 5
operation. The inspector stated that this area was unresolved (317/82-07-08)
and would be examined by a Specialist NRC Inspector during the review of the
integrated test results. The inspector further noted that the point regarding
integrated test failure became moot following discovery by the licensee
(paragraph 11) that Unit I had been operated throughout Cycle 5 with contain-
ment leakage above allowable.
11.
a.
Review of Licensee Event Reports (LERs)
LERs submitted to NRC:RI were reviewed to verify that the details were
clearly reported, including accuracy of the description of cause and
adequacy of corrective action. The inspector determined whether further
information was required from the licensee, whether generic implications
were indicated, and whether the event warranted onsite followup. The
following LERs were reviewed.
LER No.
Date of Event
Date of Report
Subject
Unit 1
82-09/3L
3/14/82
4/14/82
RPS CHANNEL B HI POWER, THERMAL
'
MARGIN / LOW PRESSURE & AXIAL SHAPE
INDEX TUS BYPASSED; TH INPUT
FAILING LOW
82-10/3L
3/19/82
4/12/82
CEA PULSE COUNTING SYSTEM &
INCORE DETECTION SYSTEM INOPERABLE
82-11/3L
3/21/82
4/16/82
CEA 21 DROPPED INTO CORE
82-12/3L
3/16/82
4/15/82
11 and 12 CHARGING PUMPS INOPERABLE
82-13/3L
3/16/82
4/15/82
12 CHARGING PUMP OUT-OF-SERVICE
FOR MAINTENANCE & 13 CHARGING
PUMP INOPERABLE
82-15/3L
4/07/82
4/23/82
PRESSURIZER LEVEL EXCEEDED 5%
PROGRAM BAND
82-16/3L
4/01/82
4/27/82
ECCS EXHAUST FILTER TRAIN INOPERABLE
82-17/3L
3/22/82
4/21/82
12 CONTROL ROOM A/C UNIT INOPERABLE
82-18/3L
4/06/82
5/04/82
12 ECCS PUMP ROOM EXHAUST FAN
REMOVED FROM SERVICE FOR SHAFT
BEARING REPLACEMENT
82-19/3L* 4/15/82
4/29/82
HYDROGEN ANALYZER INOPERABLE
_ _ _ _
___
_
. _ _ .
14
LER No. Date of Event
_Date of Report
' Subject'
Unit 1
82-22/3L*
5/03/82
5/04/82
UNIT 1 OPERATIONS IN EXCESS OF
200 DEGREES PERFORMED WITH COM-
BINED LEAKAGE RATE OF GREATER
THAN 0.60 La FOR ALL PENETRATIONS
AND VALVES SUBJECT TO TYPE B &
C TESTS DURING CYCLE 5
Unit 2
82-15/3L
3/20/82
4/19/82
NEGATIVE LIMIT SET POINT FOR
CHANNEL A 0F RPS AXIAL SHAPE
INDEX TU OUT OF SPECIFICATION
82-16/3L
4/02/82
4/30/82
PLANT COMPUTER FAILED CAUSING
LOSS OF CEA PULSE COUNT SYSTEM
& INCORE DETECTION SYSTEM
82-17/3L
4/07/82
5/04/82
23 CHARGING PUMP REMOVED FROM
SERVICE WHILE 22 CHARGING PUMP
OUT-OF-SERVICE
82-19/3L
3/28/82
4/27/82
CEA 38 REED SWITCH POSITION
INDICATOR CHANNEL GIVING ERR 0NE0US
INDICATION
b.
For the LERs selected for onsite review (denoted by asterisks aLove) 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 con-
stitute an unreviewed safety question as defined in 10CFR50.59. Report
accuracy, compliance with current reporting requirements and applicability
to other sf:s systems and components were also reviewed.
LER 82-08/3L (NRC Inspection Report 317/82-05, 318/82-05) - In
--
reviewing this incident the inspector learned that the plant
operators incorrectly believed Component Cooling Water Heat
Exchanger (CCHX) 11 was back in service when 1 of 2 posted sets
of equipment tags had been cleared. The licensee principally
attributed the cause to the failure to enter the CCHX 11 inlet
valves in the Locked Valve Deviation Log, which is reviewed by
operators during shift turnover and poor coninunications during
l
shift turnover.
The inspector discussed this event with the General Supervisor
of Operations (GS0) on 4/15/82 and stated that the NRC felt this
event was significant in that it represented a failure of the
operators on duty to carry out their basic responsibility of
being cognizant of plant status. The GS0 agreed and stated that
he would further discuss the event with his operators and remind
them of their responsibilities in this area. This item is un-
resolved pending licensee action and subsequent NRC review
(317/82-07-09).
.
-__-_ _
_ _
.-.
. _ _ _
.
15
c.
LER 317/82-19. On April 15, 1982 the licensee discovered that the flow
path from the containment to the hydrogen analyzers was isolated. This
was discovered during flow testing of the sample lines to hydrogen analyzer
cabinet IJ222, which was inoperable due to modifications to satisfy TMI TAP
Item II.F.1.6.
The licensee discovered that the test pressure would not
bleed off after the containment isolation valves were opened. A similar
test at 6:10 p.m. on the lines to the cabinet IJ220, the redundant
analyzer, which was being relied upon as the required analyzer (T.S.3.6.5.1),
showed a similar problem. The analyzer was declared inoperable, personnel
entered the containment, discovered that the three manual stop valves to
the cabinet were shut, and reopened the valves at 6:30 p.m., terminating
the event. Subsequent investigation showed that the manual stops to the
redundant analyzer were closed, and a flow test on Unit 2 was successfully
performed.
The licensee detennined that the valves had apparently not been returned
to service following local leak rate testirig (between November 21-28, 1980)
consequently all Unit 1 operations in Modes 1 and 2 during Cycle 5 were
without the required hydrogen analyzers. Licensee review of this event
revealed the following principal causes and planned corrective actions.
(1) The valves did not appear in the NSSS Sampling Operating
Instructions' valve list and consequently no verification
of the valves' position prior to entering Mode 4 on January 8,
1981 was performed.
(2) The tagging procedure used at the time of this event did not
provide for returning valves to a specified position when tags
were cleared nor did it provide for a second individual verifying
that the valve is returned to its proper position after a tagout.
A task force reporting directly to the Plant Superintendent had been
established in February,1982 to walk down all piping systems within
Calvert Cliffs with the following objectives:
(1) Verify the correct arrangement of valves on the piping and instru-
ment diagrams (P& ids) and to add or delete valves from the P& ids
and the operating instructions' valve lists to reflect as-built
conditions.
(2) Ensure that the numbering, descriptions, and operating positions
of all valves listed in the Operating Instructions' valve lists
are correct.
(3) Attach metal identification tags to each valve.
Every process system valve in the plant is to be physically checked regard-
ing its location, function and operating position at the conclusion of this
effort. The Operating Instructions' valve list for each system will be
checked to ensure that all valves are included along with their correct
number, description, location, and operating positions after each system
is walked down to ensure completeness and accuracy of the valve lists.
All valves in the facility will have metal identification tags attached
for facilitating valve lineup checks, restoration of equipment to service
and to minimize system transients due to misoperation of valves. All
.
._
-
-
-
16
walkdowns and updated valve lists will be complete for all safety
related systems for both units by December 31, 1982.
Further, the licensee stated that Calvert Cliffs Instruction ll2C
Safety and Safety Tagging was revised in June,1981 to incorporate a
l
system by which 2 operators are used to return equipment to service
and to verify that the equipment is returned to service correctly.
The procedure provides for documentation of this verification and of
the repositioning of valves and other components after maintenance or
testing.
If the Senior Control Room Operator directs valves to be
repositioned differently from the nomal operating position after
testing due to operating conditions, this is also documented. With
j
the revision of this instruction, additional verification is being
perfomed by qualified operators of the position of equipment restored
to operability after testing or maintenance consequently minimizing
the possibility of a recurrence of this event.
.
The inspector reviewed the circumstances surrouding this event including
discussions with personnel and review of documents and the report.
The following procedures and drawing were reviewed.
0131B, NSSS Sampling System, revision 4 approved 1/20/82.
--
Coment: This procedure describes the operation of the H2
analyzing system. As noted by the licensee, the valve check-
list appended to the procedure did not include the stop valves
inside the containment. This procedure also provided the path,
through the H2 analyzers, to obtain post-accident containment
radioactivity samples pending installation of the Post-Accident
Sampling System.
0141 A, Hydrogen Recombiners, revision 1 approved 3/2/77.
--
Comment: This procedure does not address use of the hydrogen
analyzer readings.
01 41B, Hydrogen Purge System Operation, revision 2 approved
--
3/20/79. Comment: System operations did not rely on readings
from the hydrogen analyzers.
E0P5, Loss of Reactor Coolant, revision 12 approved 3/6/81.
'
--
Comment: This procedure requires placing the hydrogen recombiners
in service prior to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the start of the incident, with-
cut reliance on H2 readings. The safety analysis presented in
Section 14.19 of the FSAR, concludes that the recombiner would be
started when hydrogen concentration reaches 3% or approximately
9.55 days after the start of the LOCA.
OM 463, Piping and Instrument Drawing for the Gas Analyzing System,
--
Units 1 and 2, revision 3 dated 5/26/81. Coment: This drawing
shows the valves in question and lists their position as locked open.
(Containment No.1 North Shield, Containment No.1 Elevation 135,
Containment No. 1 Elevation 189.)
--
.
-
.---.-- _-. _ , _
_ _ _ _ _ ~ _ -
_ . , _
- - _ .
_.
-
.
.
17
STP M-571-1, Local Leak Rate Tests, revision 3 approved 9/24/80.
--
Coment: This procedure isolates the hydrogen analyzer flow
path but does not include restoration lineups. The inspector
questioned various operators concerning tagging for the purpose
of local leak rate testing (not required by the procedure). They
stated that the penetrations may or may not be tagged, depending
on the particular circumstances. The inspector questioned the
licensee regarding this aspect in light of the statement that
revised tagging requirements would minimize the potential for
recurrence. The licensee stated that the STP would be revised
to require tagging.
The inspector also questioned the licensee concerning short-tenn corrective
action in case another, similar system was misaligned as a result of
local leak rate testing without subsequent proper lineup on startup or
as otherwise necessary.
Because Unit 1 shutdown the next day following
the event no further action was necessary (all local leak rate testing
is to be controlled by tags). The licensee stated that Unit 2 penetra-
tions which were isolated during local leak rate testing would be
investigated.
Technical Specification 3.6.5.1 requires that two independent containment
hydrogen analyzers shall be operable in Modes 1 and 2.
Continued
operation in a degraded mode is allowed for a period of time with one
analyzer out-cf-service. Unit 1 operation during Cycle 5 without an
operable hydrogen analyzer is a violation (317/82-07-10) of Technical Specification 3.6.5.1.
d.
LER 317/82-22. At 2:00 p.m. on May 3,1982 the licensee confinned that
from 12/18/80 until 4/18/82 all Unit 1 operations in excess of 200 degrees
had been perfonned with a combined leakage rate greater than allowed by
Technical Specifications. This was discovered during a review of the
latest Containment Local Leak Rate Test Procedure (STP M-571-1, revision
3 approved 9/24/80) and the latest test results completed December 18,
1980.
Technical Specification 3.6.1.2.b requires that containment combined
leakage rate shall be less than 0.60 La (La)= 0.2 percent by weight of
the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 50 p(La
sig for all penetrations and
valves subject to Type B and C tests.
,T
Pa are defined in 10CFR Part 50, Appendix J.)ype A, B, and C tests and
The results of the test
completed on December 18, 1980 were found to be 0.773 La, however, the
required action of restoring the leakage to within limit prior to
exceeding 200 degrees was not taken.
One contributing factor which led to operation above allowable containment
leakage limits was an error introduced into STP M-571-2 during a general
revision on 9/24/80. At that time, the limit, previously stated simply
as the maximum allowable leakage - 207,600 sccm (standard cubic centimeters
per minute), was changed to list 207,600 scem as the administrative limit
and 346,247 as the Technical Specification limit. The engineer changing the
procedure apparently confused La (346,247 sccm), the maximum allowable
, - , - ,
'
18
leakage rate (10CFR50, Appendix J definition) with the Technical
Specification limit (0.6 La).
The inspector independently calculated the required leakage rates using
a Containment Free Volume (FSAR Section 5.1.2.1) of 2,000,000 ft3 and
,
Pa of 50 psig with a resultant leakage rate of 207,700 secm. This
l
rough calculation confirmed the licensee's conclusion that the administra-
tive limit specified in STP M-571 was in reality the Technical Specification
limit (0.6La)-
The inspector reviewed the following procedures.
STP M-471-1, Air Locks Door Operability and Leak Rate Test,
--
revision 2 approved 9/3/80. Coment: This was a general revision
for format and content. An administrative limit of 207,600 seem
was added and a TS limit of 346,247. The Plant Operations and Safety
Review Comittee (POSRC) approved the revision in meeting 80-120 on
9/3/80.
-- STP M-571-1, Local Leak Rate Tests, revision 3, approved 9/24/80.
Comment: The POSRC approved the revision in meeting 80-130 on
9/24/80. This procedure change was also a general revision and
changed the administrative and TS limit.
Results of STP M-571-1, Local Leak Rate Tests, completed 12/18/80.
--
Coment: The remarks section contained the following note:
"The Administrative leakage limit (running total of all
test, including data from the previous performed LLRT
on penetrations not tested yet this outage) of 207,600
sccm was exceeded, running total is 267,615.21 scem
with 232,051.34 due to the leakage of penetrations ZWB8,
ZWC3, ZEC2, and ZEC7.
MR issued for corrective action.
Follow up Action MR's issued to Electric Shop for pene-
trations, further FCR pending. Final leakage 267,709.75
sCCm."
The POSRC approved the completed test results in meeting 81-22 on
2/2/82.
The inspector reviewed the POSRC meeting minutes listed above and noted
that all items reviewed were approved without comment. Several members
present were questioned regarding the content of the review but they
indicated that it was too far in the past to recall. The POSRC Chaiman
indicated that the STP results were probably approved because the procedure
stated that the results were between the administrative and TS limits and
ccrrective actions had been initiated.
The inspector noted that the test failure was caused principally by four
electrical penetrations (total leakage 0.67 La). The penetrations involved
were all Type 2E Electrical Penetrations made by Amphenol, Sams Division.
The inspector reviewed historical test results for the four penetrations
and noted the following progressive deterioration:
_.
,
_ _ _ _ _ _____
_ _ _ _
.
.
Preop
5/76
3/77
3/78
~7 /79
10/80
ZWB8
10
0.4
7
1393
23043(1419)
(28772)
ZWC3
4
0
0
22
1810(2917)
(46408)
ZEC2
5
0
240
4790(4464)
(76777)
-
ZEC7
3
0
-
94
3380(1310)
~(80112)
Total
22
0.4
1749
(10,110)
(232,069)
-
Parenthetical values are as-left condition. Other values are listed
as-found. All numbers in sccm.
The inspector asked the licensee about individual limits (both administrative
and absolute) for the results of individual penetrations. Although valves
(Type C tests) contained such limits,none were specified for the electrical
penetrations. The licensee stated that the valve values were obtained from
codes and standards, however, these were not available for electrical
penetrations. As a result the licensee started up with 39% of the allowable
combined leakage coming from a single (ZEC7) penetration, without successful
repair. This was another contributing factor to the event.
The inspector questioned the licensee concerning the as-found condition of
the penetrations following Cycle 5 operation in light of the noted progressive
deterioration. This information would allow quantification of the leakage
to detemine how much above the limit the leakage was at the end of the
cycle. The inspector was infomed that these penetrations were included
in those which had been imediately removed from the containment without
prior testing upon shutdown on April 17,1982 (see paragraph 10). This
action was contrary to the NRC position on Type B and C leakage testing
and resulted in an inability to establish how bad the leakage was at the
time of shutdown. The penetrations are bein
type (Conax Type 2E Electrical Penetrations)g replaced with an improved
The penetrations will be
.
welded to the containment liner versus the previous design which incorporated
a bolted joint with two concentric 0-rings.
In addition, the cable passages
have been changed to include an improved mechanical joint and better epoxy
material. A Type A (integrated) test will be perfomed after the current
refueling outage. The inspector stated that operation of the facility
between 12/18/80 until 4/18/82 with a combined containment leakage rate
greater than allowed was a violation (317/82-07-11).
The licensee stated that although similar procedural errors existed in the
Unit 2 procedures, the actual results of Unit 2 combined leakage tests were
always within required limits.
12. Review of Periodic and Special Reports
Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed. That review included the following:
Inclusion of infomation required by the NRC, test results and/or supporting
infomation consistency with design predictions and perfomance specifications,
- - - _
. - - .
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_.
-_.
-
. _ _
__
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._-.
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20
planr.ed corrective action adequacy for resolution of problems, determination
whether any information should be classified as an abnormal occurrence, and
validity of reported information. The following periodic report was reviewed.
'
March,1982 Operations Status Reports for Calvert Cliffs No.1 Unit
--
and Calvert Cliffs No. 2 Unit, dated April 15, 1982.
During the review of the March,1982 Operations Status Report the
inspector noted that the report distribution was not according to
1
the latest Technical Specification change (issued March 9,1982).
The licensee stated that a copy of the March report would be sent
to the correct addressee and that the distribution would be cor-
rected for future reports. A subsequent revised report was sent
on May 5,1982 to the correct distribution.
13. Unresolved Items
Unresolved items are matters about which more information is required to
determine whether they are acceptable. Unresolved items are discussed in
paragraphs 2, 8, 9,10,11, and 12 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 findings. A
summary of findings was also provided to the licensee at the conclusion of
the report period.
_
>
,