IR 05000317/1987001
| ML20206C386 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 03/30/1987 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206C317 | List: |
| References | |
| 50-317-87-01, 50-317-87-1, 50-318-87-01, 50-318-87-1, IEB-83-03, IEB-83-3, IEB-86-003, IEB-86-3, NUDOCS 8704130045 | |
| Download: ML20206C386 (20) | |
Text
--.
.
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
,
Docket / Report: 50-317/87-01 License:
DPR-53 50-318/87-01 DPR-69 Licensee:
Baltimore Gas and Electric Company Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Dates:
January 12, 1986 - February 28, 1987 i
Inspectors:
T. Foley, Senior Resident Inspector yTrimle,ResidentInspector h
70 87 Approved:
/'.
/
.
(). E. Tdi p, Chief, Reactor Projects Section 3A
' Ddte Summary: January 12 - February 28, 1987 (Inspection Report 50-317/87-01, 50-318/87-01)
Areas Inspected: (1) routine facility activities, (2) operational events, (3) main-
<
tenance, (4) surveillance, (5) licensee initiatives relating to SALP, (6) addi-tional inspections of LCOs, (7) radiological controls, (8) NRC/BG&E meetings, (9) physical security, (10) Licensee Event Reports, (11) IE Bulletins, (12) TMI Action Plan Item, (13) reports to the NRC, and (14) licensee action on previous
- inspection findings.
Inspection hours totalled 196.
Results: A Unit 1 manual reactor trip following a loss of Instrument Air (IA) pres-
sure pointed out a possible need for modifications to enhance IA system reliability.
Additionally, there were indications, which need to be further evaluated, that an accumulator-supplied back up air system may not have functioned as designed (detail 3).
A second Unit 1 manual trip following turbine run back was principally caused by an inadequate procedure (detail 3).
An automatic reactor trip on low steam generator (SG) level resulted from the failure of a SG 1evel control system com-
,
i
,
ponent (downcomer level lead / lag unit) (detail 3).
An assessment of the control i
room environment determined that, while control room operation was good, several l
distractions could be removed (detail 6).
i
,
8704130045 870401
l
---
_. _ _
_
_
_
- -
_ _ _ -
__
.
DETAILS Within this report period, interviews and discussions were conducted with various licensee personnel, including reactor operators, maintenance and surveillance technicians and the licensee's management staff.
1.
Summary of Facility Activities Unit 1 At the beginning of the period, Unit 1 was returning to power operation (unit paralleled to the grid on January 12, 1987) following a refueling outage.
The unit operated at 100% power until it was manually tripped on January 27, 1987, following a loss of instrument air pressure due to an operator error in returning the instrument air system to a normal valve alignment at the conclusion of a system performance test (details in Section 3).
Two conden-sate booster pumps were damaged during the event, which delayed unit start up until January 31.
On February 1, Unit 1 was manually tripped following a turbine run back due to low stator cooling liquid pressure (details in Sec-tion 3).
The manual trip was in anticipation of an automatic trip on high reactor coolant system pressure.
The root cause was an inadequate procedure which permitted the reduction of hydrogen and stator cooling pressure below the run back setpoint.
The unit returned to power on February 2.
On February 7, the unit was removed from the grid to repair an oil leak on a turbine in-tercept valve.
The unit remained off line an additional 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> to find and correct a ground on #11 Vital AC Bus.
The unit returned to power on February 8 and remained at power until the end of the report period.
Unit 2 Unit 2 operated at full power until February 28.
At that time, the unit tripped on low steam generator water level due to a level control system failure (details in Section 3).
The unit had been in operation for 169 con-secutive days.
Facility The fifth INP0 evaluation of the Calvert Cliffs facility was performed during the period of February 2-13, 1987.
A follow-up NRC inspection of the Post Accident Sampling System was held dur-ing the week of February 23, and an NRC inspection of non-licensed operator training was held during the week of February 17, 1987.
General Housekeeping remains good.
During several meetings with NRC Region I initiated by plant management, the licensee demonstrated deliberate on going efforts to address concerns and weaknesses noted during the previous SALP period.
Efforts to demonstrate a
-
.
pro-active attitude were noted in maintaining Unit 1 off-line an extended period to clear grounds which had been tolerated previously.
Changes have been made in the I&C Department in an effort to improve the staffing and sup-port weaknesses previously identified.
Maintenance initiatives to reduce Maintenance Request backlogs, enhance valve repacking, install ground detec-tion devices, upgrade reactor trip breakers, feed water system, and Reactor Coclant pump surge capacitors, and efforts to reduce plant trips and reduce the number of control room instruments out-of-service were discussed with the inspector.
Maintenance efforts appear to be properly focused.
Results of these recent efforts will be assessed in a future inspection.
2.
Review of Plant Operation - Routine Inspections a.
Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's instrumentation, recorder traces, protective systems, control rod positions, containment tempera-ture and pressure, control room annunciators, radiation monitors, efflu-ent monitoring, emergency power source operability, control room logs, shift supervisor logs, tag out logs, and operating orders.
In early February, the Reactor Coolant System daily water balance, one method of leak detection, displayed an increasing trend, increasing by about 0.1 gpm every two or three days.
(The accuracy of the water balance is often 0.2 - 0.3 gpm or more depending on plant conditions.)
Simultaneous with this trend, the Resistance Temperature Detector (RTD)
downstream of the Pressurizer Safety Valves and the Power Operated Relief Valves also indicated an increase in temperature.
The licensee proceeded to perform a leak isolation procedure to determine which was leaking.
This took several days.
It was subsequently determined that a Pressuri-zer Safety Valve was leaking into the Reactor Coolant System Quench Tank.
,
This presented several problems in that it required additional use of demineralized water, increased radioactive waste and the processing thereof, and caused additional distraction to the reactor operators in monitoring, initiating cooling and draining of the tank.
Shutting down and repairing the leak was considered; however, the planned shut down was delayed / scheduled for March 27.
This was done to allow time for parts to arrive from the vendor, Target Rock, to rebuild a pressurizer vent valve which was isolated in January due to weepage. Technical Specifications 3.4.13 " Reactor Coolant System Vents" requires that these pressurizer vent valves, if inoperable, be fixed prior to restarting following any shutdown of sufficient duration.
The licensee, therefore, planned a shutdown to repair both the pressurizer vent valve and safety relief valve, and to tolerate the pressurizer safety relief valve weepage until that time.
No unacceptable conditions were noted.
_ _.
-.
.- -
'
.
,
b.
Licensee Identified Violations
10 CFR 2, Appendix C.V, Enforcement Actions, states, "NRC wants to en-courage and support licensee initiative for self-identification and cor-rection of problems." The resident inspectors have urged the licensee to improve their methods for self-identification of problems and estab-lish controls to formally capture and track problems that meet the guid-ance provided in 10 CFR 2, Appendix C, for a Licensee Identified Viola-tion.
The following is a list of problems which the licensee has iden-tified, incorporated into some tracking system, and which otherwise meet the requirements of 10 CFR 2.
Event Date Requirement (1)
Isolation of Instrument Air 01/27/87 Failure to properly imple-System ment a procedure / operator error - T.S. 6.8.1 (2) Turbine Run Back 02/01/87 Failure to properly maintain a procedure - T.S. 6.8.1 The details of these events are discussed in detail 3.
No unacceptable conditions were noted.
c.
System Alignment Inspection Confirmation of system operability was made of selected piping system
-
trains. Accessible valve positions and status were examined.
Power supply and breaker alignment was checked.
Visual inspection of major components as performed.
Operability of instruments essential.to system performance was assessed.
The following systems were checked:
j Unit 1 Charging System checked on January 14, 1987
--
Unit 1 and 2 Auxiliary Feed Water System checked on January 23,
--
1987.*
!
- For this system, the following items were reviewed: the licensee's system lineup procedures; equipment conditions / items that might degrade system performance (hangers, supports, housekeeping, etc.); instrumenta-tion lineup and operability; valve position / locking (where required) and position indication.
During inspection of the Auxiliary Feed Water (AFW) System, the inspector
discovered a broken hanger on the Unit 2 AFW pump recirculation line to condensate storage tank #12.
Additionally, he noted that print OM 59, i
Sheet 1, Rev. 19 showed a valve in the recirculation line, 1-AFW-161,
.
'
-
.
-
-
- - _ _
-
_ - ___ _
._.
_ _ _ _ _ _. -
-
. _ _ _ _ _ _. _ _,_
_
-
'
.
that apparently does not exist.
These items were reported to the systems engineer for correction.
It was later determined that this was a non-essential valve; the inspector will follow licensee corrective actions.
The support was later reinspected and found to be acceptable.
During inspection of the Unit 1 charging system, the inspector noted that the #12 charging pump, which is powered by ZB safety channel power, is equipped with an oil level sensing instrument which is powered by either ZA safety channel power or channel A power (identification markings for both channels were noted on the cable conduit to the device).
The level instrument provides annunciation alarm only.
The inspector asked the system engineer to confirm whether or not the plant design separation criteria permitted the association of a ZA powered device on a ZB com-ponent.
The inspector also noted that insulation was missing from a small length of a heat traced Boric Acid Storage Tank suction line and that the discharge relief valve for #12 charging pump appeared to be periodically lifting.
The later two problems were referred to the shift supervisor for resolution.
The inspectors will follow this issue in subsequent routine inspections.
No unacceptable conditions were noted.
d.
Biweekly and Other Inspections During plant tours, the inspector observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifica-tions; and the use of radiation work permits and Health Physics proce-dures were reviewed.
Area radiation and air monitor use and operational status was reviewed.
Plant housekeeping and cleanliness were evaluated.
Verification of several tag outs indicated the action was properly con-ducted.
Auxiliary Feed Water During the period the inspector became aware of an internal concern re-garding the Auxiliary Feed Water System (AFW) which was being reviewed by the licensee's mechanical design engineering group.
The principal piping for the Auxiliary Feed Water System is seismic category I.
How-ever, the pump minimum flow recirculation lines are non-seismic and run unprotected through the non-seismically qualified turbine building.
The fact that the recirculation lines are not seismic was acknowledged and found acceptable by the NRC in an SER dated March 21, 1984 regarding
Generic Letter 81-14, (regarding seismic qualification of AFW systems).
This was based on a conclusion that "the minimum flow requirement is not an important safety parameter with respect to other one-time system i
functions under emergency conditions and failure of this portion down-stream of the first restriction orifice will not significantly affect the AFW system function" and "no problems will result (if the recircula-tion pipe breaks) because the increase in flow through the line would be minimal compared to that available at the pump suction".
The NRC
_
_
...
.
review did not consider the adequacy of the amount of available conden-sate given the system leakage that would result from a recirculation line break.
Each motor driven AFW pump has a recirculation flow of about 150 gpm, and each steam driven pump has a recirculation of 80 gpm.
If the AFW system were required to cool down both units in the event of a loss of off site power, total recirculation flow, and therefore leakage, could be as high as 460 gpm.
On their own initiative, the licensee determined that the adcquacy of condensate supply should be evaluated.
The inspec-tor asked to be informed of their conclusions.
The licensee agreed to provide this information.
No unacceptable conditions were noted.
3.
Operational Events Instrument Air Reactor Trip On January 27 at 6:09 p.m. Unit 1 was manually tripped from 100% power due to a loss of Instrument Air (IA).
At 6:18 all Reactor Coolant Pumps (RCP)
were secured due to Loss of Component Cooling Water (CCW).
The loss of air
,
causes CCW containment isolation valves to fail shut isolating CCW to the RCPs.
The plant remained on natural circulation until 6:25 p.m when air was re-covered, valves were repositioned, and RCPs restarted.
All safeguard features performed their intended functions.
The loss of air was caused by operator error repositioning valves following completion of a performance evaluation test on the IA system.
Upon completion of the performance evaluation, PE 1-19-4-0-M Instrument Air System Flow Check performed in accordance with Operating Instruction (0I-19), the plant operator notified the control room operator of the completion of the test and continued with his plant tours.
Shortly thereafter the Low Instrument Air Pressure Alarm energized.
The plant operator was summoned to check the IA line up and requested to bypass the IA air dryers since they had previously malfunctioned.
This was done and air pressure continued to drop.
The Shift Supervisor (SS)
arrived on the scene and noted that the IA header air pressure (discharge of
the compressor) was normal at 100 psi.
Upon rechecking the restoration lineup from the PE, the SS noted that the air after-filter inlet valve (IA-155), a valve very close to the three valves required to be operated in order to per-form the PE, was shut.
However, the IA pressure had continued to decrease and control room operators had already tripped the plant when air pressure was no longer effective in operating the Feed Water Regulating Valves.
The reactor was manually tripped when air pressure decreased to 30 psi and steam generator levels reached -30 inches.
The main feed water system was
,
secured and auxiliary feed water was used to control steam generator water levels.
Seven minutes after the trip, the reactor coolant pumps were also
'
secured because the component cooling supply valves had shut on loss of air.
The atmospheric dumps and turbine bypass valves had also shut and, as RCS tem-perature increased, pressure began to increase.
-
-
..
.-
. _-
-
...
.
. _.
-
.
a During the event, primary plant pressure increased to 2370 psig or within 30 psi of the safety valve setpoint.
This was due to the inability to spray the
>
i pressurizer because of loss of RCP differential pressure causing a loss of main spray.
Operators delayed use of auxiliary spray, which was available, because restoration of IA and RCPs was imminent.
The inspectors discussed this aspect of the event with several sources, each providing different views and insights.
In general, the operations personnel were not confident that the air accumulators designed to provide reserve capacity for cycling several valves were capable of fulfilling their function
.
after a minimal period of time.
This was apparent when the plant tripped and the Atmospheric Steam dump valves were required to be overridden open (re-quires 20 psi air pressure) whereas a trip signal is supposed to automatically insert a signal to open the valves with 60 psi air pressure.
The failure of the steam dump valves to automatically open indicates an apparent insuffi-cient volume of air.
Some operators said Auxiliary Spray was not used because
I other actions were imminent which would correct the cause of overpressure.
Other operators stated that Auxiliary Spray was attempted, however, because of possible slow valve stroke time, (possibly low IA pressure), it was never fully implemented before main spray was re-established.
Still, among those with whom the inspector talked, none had confidence that that segment of the IA system had sufficient air to operate the Auxiliary Spray valves, Atmos-pheric Steam dumps, the RCS sample valves, and several others.
The inspector requested the licensee demonstrate to operators and to ascertain l
for themselves that this segment would perform its design function.
At the l
close of the inspection period, the licensee had tested the check valves as-i sociated with the system to ascertain they did not leak.
(Following the close of the inspection period, the licensee determined that the instrument air system was not designed to accommodate operation of the atmospheric steam dumps.
An abnormal operating procedure was revised to require that, upon loss of instrument air, operators would start the air compressors which provide control air for salt water systems.)
The inspector noted that several valves within the system are designed as
,
" Continuous Bleed" air valves and the check valve test did not adequately address the concern.
The inspectors are following further licensee evalu-ations to address this concern.
j Subsequent to the trip,11 and 12 condensate booster pumps were found in a seized condition.
It is currently assumed that the demineralizer outlet valves shut on loss of air.
The bypass valve, which is designed to open when high differential pressure exists across the cleanup train, failed to open.
Lack of an adequate water supply to the condensate booster pump suction re-l sulted in overheating and seizure.
At 6:25 p.m. Instrument Air was returned to normal and RCS flow was reestab-l lished.
.
--. -
- - - - - - - - - - - - - - -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
- --
-.
.
.
- -.
-
-.
.
_ - -.._.
-
.
This event was caused by the Turbine Building Operator shutting the wrong valve while performing a valve lineup.
To prevent recurrence of this event, the following actions have been taken: (1) the General Supervisor-0perations
'
has reviewed this event will all operators to emphasize the importance of ensuring valve lineups are performed correctly; (2) An engineering analysis is being done to identify modifications that can increase the reliability of
.
!
the Instrument Air system; and (3) the turbine building operator received
]
appropriate personnel action in accordance with corporate employee policies.
NRC is concerned about secondary system problems causing plant trips.
The reliability of the IA system (corrective action No. 2) should be evaluated to determine what modifications could be made to bypass the many supplemental
,
components that improve the quality of the air, and facilitate system ability j
to recover from such an event, if not enhance the reliability of the system.
j Malfunctioning Instrument Air components occur which indirectly lead to reac-
.
tor trips, however, most are averted by alert operators running several
{
flights of stairs to bypass some of the non-vital components.
A modification to perform this bypass function from the control room has been discussed by
,
licensed operators and that should be considered for use in averting future
plant trips of this nature.
-
Manual Reactor Trip / Turbine Run Back i
At 12:35 a.m. on February 1,1987, Unit 1 was manually tripped following a
'
turbine run back from an initial plant power level of 50%.
The reactor was manually tripped in anticipation of an automatic reactor protection system
<
trip on high primary plant pressure.
The turbine run back was due to a low
!
generator stator liquid cooling pressure.
Prior to the trip the licensee had experienced problems with inleakage of air into the generator (resulting from an inoperable hydrogen seal oil vacuum pump which prevented removal of en-
,
trained air from the seal oil) that diluted the hydrogen.
To restore hydrogen purity operators initiated a " bleed and feed" operation per Operating Instruc-tion 01 43A and 0I 108.
Figure 7 of OI 43A indicated that hydrogen pressure
,
could be reduced to as low as 5 psig.
Operators decided to reduce pressure to 30 psig and felt this would leave an adequate margin to the low limit.
Stator liquid pressure automatically adjusts to follow and remain about 3 psi
below hydrogen pressure down to a minimum pressure limit of 22 psig.
Neither i
operating instruction warned that a turbine run back would occur at 44 psig in the stator liquid cooling system.
At one time the run back was set for 13 psig.
The operators recalled that previous setpoint and did not realize it had been increased to 44 psig.
Although there is an annunciator alarm to warn of low liquid pressure, that annunciator shares a master alarm window with other annunciations. Unfortun-ately, one of the other annunciations was in alarm at the time which masked the presence of the new low liquid pressure condition.
Additionally, there is only a 1 psi separation between the low liquid pressure alarm and the run I
back, and each of those functions is initiated by a separate pressure sensor.
,
Therefore, minor sensor error or calibration differences could allow run back j
to occur before the alarm.
!
,
_
_ _ _
_ _ _ _ _ _ _ _ _
-
.
l
!
The plant performed as designed following the reactor trip.
The licensee is evaluating several possible corrective actions.
Both OIs were changed to require hydrogen pressure to be kept above 50 psig.
The root cause is believed to be a failure to appropriately revise the OIs at the time the run back pressure setpoint was changed.
The inspectors will review licensee corrective actions upon issuance of the licensee event report (LER No.317/87-03).
Unit 2 Reactor Trip On Low Steam Generator level At 11:58 p.m. on February 28, 1987, Unit 2 tripped from 95% power on low level in #21 steam generator (SG). A false high steam generator level signal was sent to the feed water flow controller by a malfunctioning level processing circuit. This caused the feed water flow controller to close the feed water regulating valve for #21 SG.
Plant systems functioned as. designed following the trip and the plant was quickly stabilized.
The unit was returned to power at 12:15 a.m. on March 2, 1987.
The malfunction occurred in the downcomer level lead / lag unit. This unit compensates the SG 1evel signal for the ef-fects of SG shrink and swell during transient conditions.
At the end of the inspection period the licensee planned to send the failed unit to the manufacturer to determine the root cause of failure.
4.
Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and mainten-ance procedures, codes and standards, proper QA/QC involvement, safety tag I
use, equipment alignment, jumper use, personnel qualifications, radiological controls for worker protection, fire protection, retest requirements, and reportability per Technical Specifications.
The following activities were included:
--
PM-1-9-M-W-1, Weekly Travelling Screen Preventative Maintenance.
PM-1-41-M-SA-1, Oil Change of No. 11 Charging Pump
--
PM-1-36-M-23, #13 AFW Pump Oil Change
--
PM-0-FP-M-5, Emergency Fire Equipment Locker Check
--
PM-1-52-I-RQ1-15, Low Pressure Safety Injection Flow to Loop -12B Veri-
--
fication PM-1-61-I-RQ1-6, 12 Containment Spray Pump Discharge Pressure Test
--
No unacceptable conditions were noted.
-
-
.
5.
Surveillance The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal and re-storation of equipment, and deficiency review and resolution.
The following tests were reviewed:
FH-1, New Fuel Receipt Inspection
--
STP-0-87-1, Borated Water Source Operability
--
STP-0-29-1, CEA Partial Movement Test
--
STP-89-0, Fire Suppression System Weekly Check
--
STP-M-77-0, Staggered Test of Diesel Fire Pump
--
STP-0-5-1, Auxiliary Feed Water System Test.
--
--
STP-0-8-A-1, 11 Emergency Diesel Generator and 4KV Bus 11 LOCI Sequence Test
--
STP-M-152, Weekly Battery Checks No unacceptable conditions were noted.
6.
Licensee Initiatives Relating to SALP Assessment of Control Room Environment In order to ensure a satisfactory environment exists for the conduct of con-trol room operations, Region I Temporary Instruction RI-87-01 was issued to initiate control room environment inspections.
Control room environment is expected to be an input to the Systematic Assess-ment of Licensee Performance (SALP).
a.
Positive Attributes The dual unit control room at Calvert Cliffs has been observed by the resident inspectors at various times throughout the year on all shifts.
Operations performs their function in a semi-formal manner.
Operators are provided and are required to wear a semi-formal / casual uniform.
,
Their demeanor in the control room is well disciplined, effectively re-
'
sponsive, yet informal and relaxed during routine operations, however, it becomes more formal during watch turnover and more serious during
'
plant transients.
. _ -
.
.. -
,
_
..
.-
-.
-
.
Inspectors have never observed or heard entertainment devices such as radios or unrelated reading materials used in the control room.
Inter-face between operators and plant workers is calm and orderly.
Control room access is limited by administrative control and also by a physically locked door which restricts all but authorized personnel.
Housekeeping within the control room is good.
Evidence of snacks or
!
meals is rarely encountered.
The appearance is well kept and orderly.
,
i i
b.
Negative Attributes Appearance Notwithstanding the above, the material condition of the control room
.
furniture, floor, and panels appears somewhat below the standards BG&E has set for the site simulator, the modernization of engineering spaces
and facility grounds.
These areas appear manicured and provide for a professional appearance / environment.
The control room lacks the same
,
i professional pride in appearance.
Distractions
.
i Almost daily, surveillance testing is performed on parts of the Reactor Protection System or the Nuclear Instrumentation System.
Operators have i
+
to acknowledge alarms induced by the personnel performing the surveil-lance test.
Several operators have complained about this distraction without resolution.
Numerous Maintenance Requests (MRs) are found on each control panel.
This has been pointed out in several inspection reports and previous
<
SALFs.
Operators are hindered by instrumentation and controls that either are malfunctioning, inaccurate, unreliable, or, at times, missing.
Many components "in the field" are in need of repair.
The MR tags for
{
these components are located on the control boards and operators should,
and do, read these before operating the component.
This hinders the l
operation.
!
Although shift turnovers are conducted in a semi-formal method, no shift briefings occur to provide licensed operators knowledge of the activities
planned for the day.
The licensee takes pride in their exceptional planning efforts, however, the " plans" are only disseminated down to the first line supervision.
Control room operators, shift engineers and others are not provided with a consolidated briefing.
Discussion with control room personnel indicates that control room up-grades are planned for this outage (March 1987).
The licensee also
!
',
recognizes the large number of MRs on the control boards and is striving
!
to reduce them.
!
!
t
.
- - - -
_
_
___
_
_.
_
_. _ _ _ _. _
__
_
_
. _ - -.-
.
..
!
In summary, control room operation is good, however, several distractions could be removed to improve the operator's ability to respond, and the professional appearance of the control room could be improved.
,
,
7.
Additional Inspections The following review of outstanding, long term limiting conditions for opera-tions (LCOs) was conducted.
In addition to daily review of control room and shift supervisors' logs, this separate review was conducted to ascertain that LCOs carried for an extended period were not exceeding the time permitted by the " Action Statement".
The following protracted LCOs were in effect at the time of the inspection and were considered as such if they remained in effect for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
LCOs of a temporary nature, existing less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, are not in-cluded in this inspection.
The inspector's review concluded that protracted LCOs were generally carried over on a monthly basis.
The following is a list of LC0's in effect during the previous three months and the date the " Action Statement" began, followed by a brief description of the action required for each LCO:
Date
,
Date T.S.
LCOs Entered 2/1/87 3.3.3.1(30)
RIC 5415 Wide Range Noble Monitor 12/31/86 Out-of-Service 2/1/87 3.4.13(b)
Pressurizer Vents Inoperable 01/05/87 2/1/87 3.3.3.4 a Meteorological Instrument Out-of-01/28/87 Service 2/1/87 3.4.3.a Power Operated Relief Valve (404)
08/03/86 2/1/87 3.6.4.1.c Pressurizer Sample Valve PS-5465 09/25/86 i
Out-of-Service 1/1/87 3.3.3.1(3)
12/31/86 1/1/87 3.4.Ja 08/29/86 1/1/87 3.6.4.1.c 09/25/86 12/1/86 3.4.3.a 08/29/86 12/1/86 3.6.4.1.c 09/25/86 12/1/86 3.3.3.7a West Reactor Coolant Pump Fire Detec-10/30/86 tion Instruments Out-of-Service
.
- -
-
-
-
A
-
.
Date Date T.S.
LCOs Entered 11/1/86 3.3.3.7a 10/30/86
,
11/1/86 3.4.3.a 08/29/86 11/1/86 3.6.4.1c 09/25/86 Synopsis of the Applicable Action Statement TS 3.3.3.1(30) initiates the pre planned alternate method of sampling and requires submitting a report to the NRC outlining the causes of malfunction and plan for restoration.
TS 3.3.3.4a requires submitting a report to the NRC outlining the cause and plans for restoration.
TS 3.3.3.7a requires inspecting the applicable zone at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and submitting a report to NRC within 30 days outlining the cause and plans for corrective action.
TS 3.4.3a requires closing the associated PORV Block Valve and removing power to the Block Valve.
TS 3.4.13(b) requires verifying one PORV operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and restor-ing the PZR vent to operable prior to entering Mode 2 following the next hot shutdown.
TS 3.6.4.1(c) requires isolating the affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by the use of at least one manual valve or blind flange.
In conclusion, no unacceptable conditions were noted.
A copy of each of the above reports was received by the resident inspector.
Compliance with the Technical Specifications was observed in each case.
8.
Radiological Controls Radiological controls were observed on a routine basis during the reporting period.
Standard industry radiological work practices, conformance to radio-logical contrcl procedures and 10 CFR Part 20 requirements were observed.
Independent surveys of radiological boundaries and random surveys of non-radiological points throughout the facility were taken by the inspector.
,
No unacceptable conditions were identified.
- -
-
-
-
-
-
-.
- _ -.
-
-
- - -
-
-
.
9.
NRC/8G&E Meetings a.
Regarding Emergency Diesel Generator Gassing and Reactor Coolant Pump Shaft Cracking l
On February 4, 1987, licensee representatives met with NRC Region I staff l
at the Regional Headquarters in King of Prussia, Pa., in order to convey l
the complexity of the problem, the underlying causes and thought pro-l cesses during investigation of the Emer3ency Diesel Generator problem l
first identified in October 1985 and resolved in December 1986.
The l
licensee also presented the Non-Destructive Examination (NDE) results of the approximately 120 axial indications, the analysis performed, and the current plans regarding the Reactor Coolant Pump 12A shaft " cracks".
The sequence of events and details regarding the Emergency Diesel Genera-tor problems are documented in Inspection Reports 50-317/ and 318/85-32, 86-16, 86-18, and 86-19.
The licensee provided a detailed description of the system, the symptoms of the problem, the maintenance investigation, their reasoning, and con-clusions which led to a second maintenance investigation and an Emergency Technical Specification change, the overhaul activity and subsequent testing to demonstrate operability.
The licensee also determined the rcot cause of the gassing problem to be a failure of the gasket material within the inter air cooler heat exchanger.
Specifically, the end bell flange to tube sheet cork gasket and the tube sheet to heat exchanger compressed asbestos gasket both leaked.
A 30 psi hydrostatic test with water was previously utilized to demonstrate '.he integrity of the cooler.
However, after additional gassing, the test of the air coolers was re-peated utilizing a " Local Leak Rate" test device and nitrogen as the testing medium.
This test demonstrated the effects of the leaking air cooler.
l The corrective actions stated consisted of replacing the subject gaskets every six years, inspecting the coolers every refueling outage, revising operator logs to include checks of the air cooler system parameters and conducting an annual 4-to 8-hour run of each Emergency Diesel Generator.
l All questions by the NRC regional staff present received acceptable re-
!
sponses.
A second topic was presented to inform the NRC regional staff of the results of BG&E inspection of the No.12A Reactor Coolant Pump rotating assembly.
The presentation consisted of a history of industry problems related to RCP shaft cracking and BG&E's plans to inspect as a result of the in-dustry problem and unusual pump vibration signatures on RCP 12A when compared to the other RCPs.
An explanation describing the differences between Calvert Cliffs Reactor Coolant Pumps (RCPs) and those that ex-
,
.
.
. _ _ _ _
. - -
. _.
__
_ _.
._
.
perienced cracks at other utilities occurred.
The preliminary analysis made by University of Virginia and Borg Warner Industrial Products (BWIP)
of the unusual vibration signatures was discussed.
During November 1986, the licensee removed 12A RCP and began an inspec-tion of the RCP assembly with technical help of BWIP and Babcock and Wilcox (B&W).
The results revealed approximately 120 axial indications, approximately 2" long and varying in depth up to.090 inches deep.
A thermal stress and fracture mechanics analysis calculated that these cracks would arrest at a depth of.24 inches and that cracks of this nature would be expected due to temperature oscillations from pressure pulsations caused by rotating members and pressure breakdown devices.
The analysis determined that the stresses were bounded by the pressure pulse oscillation frequency of 15 hertz and 1.5 hertz.
The stresses became worse at the lower frequency, therefore 1 hertz was used instead of 1.5 hertz.
The NRC questioned the basis for the 1.5H.
The licensee stated "engi-neering judgment based on turbulent mixing".
Because the licensee de-sires added confidence with regard to the results of the analysis, they plan to request Byron Jackson to independently check the analysis for technical adequacy and conservatism.
The licensee's engineering staff reported the results to all levels of the BG&E Nuclear Division and agreed with the conclusions of BWIP that continued operations was appro-priate, that the cracks would be expected to be found on the other pump shafts, and that the cracks are benign.
The NRC staff requested that they be kept informed of the results of the confirmatory analysis.
The meeting was characterized by frank discussions.
The meeting was mutually beneficial to both NRC and BG&E.
b.
Meeting with Licensee Maintenance Department Management On the afternoon of February 25, 1987, at the request of the licensee, a meeting was held at the Region I headquarters.
In attendance were members of the licensee's Nuclear Maintenance Department management and supervision and Region I Projects and Operations Branches management, supervisors, and other personnel.
The purpose of the meeting was to afford the licensee the opportunity to present recent initiatives and department goals.
Topics presented included reduction in maintenance-related reactor trips, reduction of control room out-of-service instru-mentation, enhanced valve packing program, reduction of maintenance order backlogs, and other initiatives to improve maintenance and modifications.
No unacceptable conditions were identified.
-
. _
-
-
__
-..
-
._.
.
i
10. Observation of Physical Security Checks were made to determine whether security conditions met regulatory re-
quirements, the physical security plan, and approved procedures.
Those checks
included security staffing, protected and vital area barriers, vehicle searches
and personnel identification, access control, badging, and compensatory meas-
ures when required.
No unacceptable conditions were noted.
11.
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 cor-rective action.
The inspector. determined whether further information was required from the licensee, whether generic implications were considered, and
whether the event warranted on site follow-up.
The following LER's were re-viewed:
l LER No.
Event Date Report Date Subject Unit 1
,
i 87-01 12/10/86 02/05/87 Violation of Technical Specifi-cation for Operable Shutdown
'
,
Cooling Loops
87-02 12/03/86 02/05/87 Main Steam Piping Flaw l
87-03*
01/27/87 02/19/87 Reactor Trip as a Result of Loss i
of Instrument Air 87-04*
02/01/87 03/02/87 Reactor Trip as a Result of Tur-
,
'
bine Run Back
Unit 2 j
86-06, Rev.1 09/05/86 02/05/87 Reactor Trip Caused by Reactor
Pump Surge Capacitor Failure
- Detailed examination of these events is documented in detail 3 of this in-l spection report.
No unacceptable conditions were noted.
12.
IE Bulletin Follow Up The inspector reviewed licensee actions on the following IE Bulletins to de-termine that the written responses were submitted within the required time
!
period, that the responses included the information requested including ade-
,
j
-
.
-
o
.
quate corrective action commitments, and that the licensee management had forwarded copies of the responses to responsible on site management.
The review included discussions with licensee personnel and observations and re-view of the items discussed below.
(Closed) IE Bulletin No. 83-03: Check Valve Failures in Raw Water Cooling
--
Systems of Diesel Generators.
This bulletin was sent to the licensee on March 10, 1983.
The bulletin pointed out that the forward flow test
requirements of ASME Section XI are not, by themselves, effective in determining whether check valves are adequately performing their intended function.
The licensee responded on June 7, 1983, and August 23, 1985, indicating that (1) back flow tests were included in the IST Program, (2) front flow tests did not meet bulletin requirements, (3) monthly operability sur-veillance was performed but was not included in the IST Program, (4) no failures had occurred in operation or testing, and (5) the IST Program i
was to be modified to incorporate additional check valves not previously tested for functional performance in the rever:e direction.
The inspector discussed the status of testing these valves and determined i
that they are not currently being tested in the reverse direction.
The licensee has instead initiated an engineering evaluation of the three check valves in question to determine if they serve a useful purpose.
BG&E engineering has determined that the valves could be removed.
The licensee has now requested the designer of the system, Bechtel Corpora-tion, to evaluate the removal of the check valves prior tc final approval of removal.
Other than these three check valves, ISRW-321, ISRW-322, and 2SRW-321, the licensee's response was ascertained to be correct.
Additionally, the licensee has committed to perform an extended operability test of the Emergency Diesel Generator (EDG) (4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) which would also demonstrate forward flow capabilities of the Service Water EDG check
!
valves.
t Resident inspectors will track the removal or reverse flow testing of these check valve.
This bulletin is closed.
(Closed) IE Bulletin 86-03: Potential Failure of Multiple ECCS Pumps Due
--
to Single Failure of Air-0perated Valve in Minimum Flow Recirculation Line.
This bulletin was sent to the licensee to evaluate the possibility of minimum flow recirculation lines containing air-operated isolation valves which could result in a common cause failure of all emergency core cooling system (ECCS) pumps in a system.
-
-
.
-
.
- -
-.
.
.
. - -
-
~ _.
- -. _
_. _.
...
.-.
-
-..
. -..
.
)
.
l
'
.
The licensee responded to this on November 21, 1986, stating that Calvert
.
j Cliffs was not susceptible to the described failure for the following
reasons:
i i
'
]
(1) The installed minimum flow recirculation valves MOV-659 and MOV-660 l
are motor-operated vice air-operated.
i
!
(2) The MOVs are designed to fail "as is" vice designed to fail closed.
!
(3) The MOVs 659 and 660 are locked open with control power removed by i
a control panel key operated switch, requiring operator action to
close.
!
l
)
(4) The facility was not designed to sustain a single passive failure,
'
j i.e., the disc falling of f for no apparent reason.
The inspector ascertained that the above was correct.
The design at
{
Calvert Cliffs appears to be substantially different than the concerns
identified in the bulletin.
)
,
!
This bulletin is closed.
!
13.
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 j
plan items.
These items have been broken down into numbered descriptions j
(enclosure 1 to NUREG 0737, Clarification of TMI Action Plan Items).
Licensee j
i letters containing commitments to the NRC were used as the basis for accept-
,
I ability, along with NRC clarification letters and inspector judgment.
The i
i following items were reviewed.
j As required by Confirmatory Order dated June 14, 1984, the licensee re-
--
i sponded to the recommendations to Regulatory Guide 1.97 providing either j
hardware changes or a position of exception with respect to Regulatory i
Guide 1.97.
A letter dated January 6, 1987, from NRC to BG&E provided j
the Safety Evaluation (SE) of the licensee's submittals dated December j
1, 1984, and February 21, 1986.
The SE found the instrumentation pro-vided at Calvert Cliffs Units 1 and 2 to be acceptable with respect to Regulatory Guide 1.97 except for the following:
l (1) containment sump water level (narrow range),
.
(2) containment sump water temperature,
'
!
(3) safety injection tank level, f
(4) safety injection tank pressure, and i
(5) component cooling water temperature to the engineering safety l
features system.
a
,
l i
,
,
.
.
.
.
.
a
-
a
'
.
The licensee is required to provide details on how the above will meet the requirements of Regulatory Guide 1.97 for the five instruments by March 20, 1987.
The item will be reviewed during a future routine inspection, j
14.
Review of Periodic and Special Reports Periodic and special reports submitted to the NRC pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed.
The review ascertained inclusion of information required by the NRC, test results and/or supporting information, consistency with design predictions and performance specifications, adequacy of planned corrective action for resolution of problems, determination whether any information should be classified as an abnormal occurrence, and validity of reported information.
The following periodic reports were reviewed:
December 1986 Operations Status Reports for Calvert Cliffs No. 1 Unit
--
and Calvert Cliffs No. 2 Unit, dated January 8, 1987.
January 1987 Operations Status Reports for Calvert Cliffs No. 1 Unit and
--
Calvert Cliffs No. 2 Unit, dated February 12, 1987.
No unacceptable conditions were identified.
i
,
15.
Licensee Action on Previous Inspection Findings l
(Closed) Unresolved Item 317/82-09-02 - MR Verification by Fire Inspector.
The licensee controls work associated with fire protection, fire barriers, welding, burning, grinding or fire equipment through the use of Calvert Cliffs Instruction CCI-133 and by the FCR process, each of which require fire pro-tection considerations.
This item is closed.
(Closed) Unresolved Item 317/82-12-02 - Use of Gauges Not on Schedule fo Calibration.
This item was again identified in May 1986 and subsequent 1 classified as a violation and traced as 317/86-15-01.
This item is clot J.
(Closed) Violation 317/82-20-01 - Procedures Not Established or Technically Incorrect.
A review was conducted of the licensee's response to the violation dated September 17, 1982.
The review concluded that the licensee's response was adequate.
This item is closed.
(Closed) Unresolved Item 317/80-17-01 - Verify Licensee Implementing Require-
)
ments of ANSI N.45.2.9.
The licensee's QA Manual states that the QA Program meets the requirements of ANSI N.45.2.9 (October 1976).
The inspector veri-fled with the QA Department that the QA Department has audited this area and determined that requirements of the standard have been met.
This item is
,
close.
(Closed) Violation 318/82-05-03 - Failure to Control Drawing Changes.
The inspectors reviewed the licensee's response dated May 19, 1982, and the cor-rective actions stated therein.
The corrective actions stated and their im-plementations were found to be acceptable.
This item is closed.
(Closed) Unresolved Item 318/82-05-05 - Complete Evaluation of Correlation between Actual Liquid Monitor Response and Laboratory Analysis Estimated Re-sponse.
The licensee now monitors the release using liquid monitors, as be-fore, and also takes samples and does a spectroanalysis composite of the various nuclides.
This item is closed.
(Closed) Inspector Follow Item 318/82-25-01 - Handling and Disposing of Hydra-zine.
New procedures have been developed and incorporated into the Calvert Cliffs Industrial Safety Manual, specifically Chapter 9. Handling and Storage of Hazardous Chemicals, Liquids and Gases which will incorporate Hydrazine.
This item is closed.
(Closed) Inspector Follow Item 318/82-25-02 - Inspector Follow Item - Engi-neering Safety Features Actuation Caused by Technician Error During Testing.
The inspectors have closely monitored the facility for inadvertent ESF actu-ations and have noted a declining trend in this area.
There have been no inadvertent ESF actuations during the past year.
This item is closed.
(Closed) Inspector Follow Item 318/82-27-06 - Need Louder Plant Page During Emergencies.
The licensee has since installed an additional new and louder plant page.
This item is closed.
16.
Exit Intervies Meetings were periodically held with senior facility management to discuss the inspection scope and findings.
A summary of findings was presented to the licensee at the end of the inspectior..
1 l
1