IR 05000244/1985010
| ML17254A443 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 06/28/1985 |
| From: | Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17254A441 | List: |
| References | |
| 50-244-85-10, NUDOCS 8507160511 | |
| Download: ML17254A443 (21) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-244/85-10 Docket No. 50-244 Licensee No.
DPR-18 Priority Category C
Licensee:
Rochester Gas arid Electric Corporation 49 East Avenue Rochester, New York 14649 Facility Name:
R.
E. Ginna Nuclear Power Plant Inspection at:
Ontario, New York Inspection Conducted:
May 1, 1985 through June 15, 1985 Inspector:
W. A. Cook, Resident Inspector, Ginna Approved by:
Linvilie, C
ef, Reactor oject Section
.
2C, DRP 4 zJ'r>
at In s ection Summar Ins ection on Ma
1985 throu h June
1985 Re ort No. 50-244/85-10 k
resident inspector (13S hours).
Areas inspected included: plant activities during routine power operations; licensee action on previous findings; surveillance testing; plant maintenance; RCS/ECCS Isolation Valve Review; Licensee Event Report review; and inspection of accessible portions of the facility during plant tours.
Results:
Of the seven areas inspected, one violation was identified in the area of instrumentation/equipment surveillance, (see details in paragraph 3.b).
The reactor trip of June 6,
198S and other maintenance related events raise concerns about maintenance control and management oversight, (see details in paragraph 3.a).
8507 DOCK 05000244
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DETAILS Persons Contacted During this inspection period, the inspector interviewed and talked with operators, technicians, engineering and supervisory level personnel.
Licensee Action on Previous Ins ection Findin s
(Closed)
Inspector Follow-up Item (83-05-02):
Notification of Control Room prior to starting work.
During an earlier reporting period, facility operation was impacted by activities in the plant that the control room operators were not cognizant of.
To date, there have been no similar occurrences.
One of the apparent causes for this problem was the lack of formal information exchange between plant Operations and the Station Projects group.
The inspector determined that Operations receives daily, from Projects, a listing of active Engineering Work Requests which will be worked that day.
The inspector interviewed members of the Operations staff and concluded that plant activities are being appropriately channeled through the control room via the Shift Supervisor.
Based on interviews with control room operators it appears that they are being properly kept up-to-date and informed of plant work activities.
(Closed)
Inspector Follow-up.Item (83-24-02):
Correct low NPSH condition to main feedwater pumps.
Prior to the completion of modifications to the Heater Drain Tank (HDT) System during the 1985 Refueling Outage, numerous control room alarms associated with low net positive suction head (NPSH)
conditions to the main feedwater pumps were experienced.
The cause of the frequent alarms was determined to be the result of level oscillations in the HDT initiating HDT pump discharge pressure transients which ultimately affected suction pressure of the main feedwater pumps.
The HDT level oscillations were attributed to the additional steam and water input from the preseparator drain tanks.
The preseparator drain tanks were installed during the 1983 Annual Outage to improve steam quality to the moisture separator reheaters and reduce steam erosion to the same.
Although the low NPSH conditions had been generally self-clearing, due to the automatic actuation of the condensate bypass valve, limited operator intervention was still required and this condition posed a frequent distraction to the control room operators.
A HDT level control system modification was completed during the 1984 Annual Refueling Outage, however, this change was unsuccessful in correcting the problem.
A temporary solution to minimize HDT level oscillations was to increase HDT quench water flow.
The additional quench water flow helped to dampen level oscillations, but reduced thermal efficiency and degraded steam generator water chemistry control.
The 1985 modifications included:
resizing the HDT vent to increase steam flow to the fourth pass heaters; the installation of a level sensing shield inside the HDT to minimize the flashing effects on the level sensing system; and a reconfiguration of the quench water subsystem for
improved water chemistry control.
No significant main feedwater pump low NPSH conditions have been experienced since start-up from the refueling outage.
(Closed)
Inspector Follow-up (84-10-02):
Development of Administrative Procedures for control room notes.
The inspector identified the apparent uncontrolled usage of temporary handwritten notes to aid operators in identifying abnormal plant conditions and special instructions or precautions.
In response to this finding, the licensee instituted Operations Standing Order No.B-85-1, "Operator Aids and Operator Aid Tags" dated April 8, 1985.
The inspector reviewed this Standing Order and its implementation and determined that adequate review, approval and accountability controls have been established to ensure proper use of temporary operator aids.
(Closed)
Inspector Follow-up Item (84-22-01):
Review calibration and maintenance procedures for chlorine and ammonia detectors.
During =-an earlier review of TMI Action Plan Item III.D.3.4, "Control Room Habitability Requirements",
the inspector determined that the 'licensee had not completed the development of calibration and maintenance procedures for the control room ventilation chlorine and ammonia monitors.
The inspector reviewed the newly instituted Calibration Procedure (CP)-234,
"Calibration and/or Maintenance of Anacon Chlorine Analyzer", Revision 0, dated February 27, 1985 and CP-235, "Calibration and/or Maintenance of the Foxboro Ammonia Analyzer", Revision 0, dated April 4, 1985.
The inspector determined that CP-234 and CP-235 adequately define the necessary steps and precautions to properly calibrate and maintain their respective monitors.
(Closed)
Inspector Follow-up Item (84-24-01):
Review final corrective action for improvement of Part 21 reporting.
The inspector reviewed Administrative Procedure (A)-61, "Method of Evaluation for Reporting Requirements in Basic Components Under
CFR 21", Revision 11, dated April 17, 1985, and determined that appropriate steps have been established by the licensee to ensure the timeliness of Part 21 reports.
The inspector concluded that the Part 21 reporting evaluations implemented by A-61 provide adequate guidance to meet regulatory requirements.
(Closed)
Inspector.Follow-up (84-01-01):
Revise procedure to detail licensee actions upon receipt of Part 21 Reports.
In January 1984, the inspector determined that an April 1983
CFR Part 21 Report by Comsip, Inc.
had not been properly acknowledged and resolved by the licensee.
The Part 21 Report had been received by a licensee representative in May 1983, however, no formal means of tracking and addressing the identified deficiency was in place and the report went unheeded until brought to the attention of the licensee by the resident inspector.
The inspector reviewed Corrective Action Report No.
1526 generated by the licensee to develop the necessary processing controls and the revised Ginna Station guality Assurance Manual sections pertaining to nonconformance items and corrective actions.
The inspector determined that adequate guidance has been established for receipt and processing of 10 CFR Part 21 reports via use of the licensee's Nonconformance Report Syste The inspector had no further questions.
3.
Review of Plant 0 erations Throughout the reporting period, the inspector reviewed routine plant operations.
Activities in progress included full power operations, with the exception of the event discussed below.
On June 6,
1985, licensed operators wer e performing operability checks on all Nuclear Instrumentation System (NIS) power range channels when operation of the operate selector switch (S-303)
on channel N-41 resulted in erratic meter indications.
The operators suspended the operability checks and restored channel N-41 to normal and submitted a "Maintenance Request and Trouble Report" to identify and correct the channel N-41 deficiency.
Subsequent troubleshooting by Instrumentation and Control (I&C)
technicians determined that the operate selector switch needed to be replaced.
I&C supervision concurred with in-place replacement of the switch and electrical isolation to remove the operate selector switch was established.
While disconnecting the operate selector switch leads with a soldering iron, a previously unidentified energized lead from Instrument Bus 1D was momentarily grounded and resulted in a reactor trip from 100% power at 10:49 A.M..
The reactor tripped on an overpower delta temperature (OP Delta T) trip signal.
The licensee concluded that the grounding of Instrument Bus 1D and subsequent voltage transient resulted in a reduction in the OP Delta T trip setpoint for NIS Power Range Channel N-44.
Since NIS Power Range Channel N-41 was already defeated in accordance with the maintenance procedure, the 2 of 4 logic for OP Delta T
was satisfied and the reactor tripped as designed.
All protec-tive features and safety systems responded properly to the reactor trip.
The inspector determined that although channel N-41 electrical isolation was reviewed by the I&C technicians responsible for the maintenance, no voltage checks were performed to verify the operate selector switch was totally deenergized.
In addition, the procedure used to govern this maintenance, CP-41,
"Calibration and/or maintenance of Power Range N-41", does not address electrical isolation for component repair or replacement.
This maintenance related reactor trip and similar maintenance and troubleshooting related events reviewed by the inspector in recent months indicates an apparent lack of sufficient preplan-ning and management oversight of such activities.
This concern was addressed with the licensee at a site meeting on June 14.'ending review of the licensee's written report and analysis
of the June 6,
1985 reactor trip, the inspector had no further questions at this time.
b.
During the course of the inspection, the inspector toured accessible plant areas.
Items reviewed include radiation protection controls, plant housekeeping, fire protection, equipment tagging and security.
On Hay 29, 1985, all fire detection systems were taken out of service to troubleshoot and repair an electrical problem in the detection system power supplies.
The inspector reviewed the licensee's com-pensatory measures as specified by Technical Specification 3. 14. 1. 1 for those designated safety-related detection systems.
The inspector determined that, with one exception, all compensatory measures taken for the numerous inoperable fire detection systems were adequate.
Technical Specification 3. 14. 1. l.a. states that if containment fire detection systems are inoperable, an inspection of containment every eight hours or the monitoring of containment air temperatures hourly at a minimum of 16 representative locations is adequate compensatory action.
The licensee chose the latter.
The inspector determined that the containment temperature monitoring system utilized to satisfy this Technical Specification requirement was in calibration, although the calibration sticker affixed to the recorder cabinet showed it was overdue.
Further review indicated that this tempera-ture monitor system was not included in any station surveillance program.
The failure to incorporate the containment temperature monitoring system into a station surveillance program when designated and used to satisfy a Technical Specification limiting condition for operation, is a violation of station Administrative Procedure A-1105,
"Calibration and/or Test Surveillance Program for Instrumentation/Equipment of safety-related components" and Technical Specification 6.8 (85-10-01).
Inspector tours of the control room this inspection per'iod included review of shift manning, operating logs and records, and equipment and monitoring instrumentation status.
Safety system valves and electrical breakers were verified to be in the position or condition required for the applicable plant mode as specified by Technical Specifications and plant lineup procedures.
This verification included routine control board indication review and conduct of a partial systems lineup check of the Service Mater System on Hay 24, and the 1A and 1B Emergency Diesel Generators on Hay 24.
4.
Surveillance Testin a.
The inspector witnessed the performance of surveillance testing of selected components to verify that the test procedure was properly
approved and adequately detailed to assure performance of a satis-factory surveillance test; test instrumentation required by the procedure was calibrated and in use; the test was performed by qualified personnel; and the test results satisfied Technical Specifications and procedural acceptance criteria, or were properly resolved.
b.
The inspector witnessed the performance of portions of the following tests:
Periodic Test, (PT)-2.2,
"Residual Heat Removal System",
performed on June 10, 1985.
PT-12.2,
"Emergency Diesel Generator 1B", performed on June 14, 1985.
5.
Plant Maintenance During the inspection period, the inspector observed maintenance and problem investigation activities to verify compliance with regulatory requirements; compliance with administrative and maintenance procedures; required QA/QC involvement; proper use of safety tags; proper equip-ment alignment and use of jumpers; personnel qualifications; radio-logical controls for workers protection; and ascertain reportabi lity as required by Technical Specifications.
b.
The inspector witnessed the following maintenance activity:
The performance of stuffing box replacement on the 1C coolant charging pump in accordance with Maintenance Procedure (M)-11.4.6, "Changing Pump Stuffing Box Maintenance",
Revision 6, February 15, 1984, performed on May 21, 1985.
The inspector found no discrepancies.
6.
Evaluation of Surveillance and Maintenance Pro rams for Isolation Valves Between the RCS and Low Pressure ECCS s
The inspector conducted a review of the Emergency Core Cooling Systems (ECCS's) to evaluate the potential for overpressurization of these systems.
As discussed in IE Notice No. 84-74, "Isolation of Reactor Coolant System from Low-Pressure Systems Outside Containment",
dated September 28, 1984, potentially significant problems in maintaining isolation boundaries between the high pressure RCS and lower pressure piping systems have increased the likelihood of an intersystem Loss of Coolant Accident (LOCA) which would bypass the primary containment.
The inspector reviewed the following areas:
Verification of the as-built isolation interfaces between high and low pressure piping system 'Evaluation of isolation valve surveillance requirements and procedures.
Evaluation of applicable maintenance procedures.
Licensee response to NRC or industry disseminated operating experience regarding isolation valve problems and training.
Site specific isolation valve problems and actual or potential overpressurization of ECCS piping or components.
The inspector reviewed the following drawings to identify all RCS/ECCS interfaces and system configurations:
Ginna Station Drawings-No. 33013-1247,
"Auxiliary Coolant Residual Heat Removal P&ID",
Revision 3, dated 2/19/85.
No. 33013-1260,
"Reactor Coolant PAID", Revision 1, dated 1/16/85.
No. 33013-1262,
"Safety Injection and Accumulator PAID", Revision 1,
dated 1/15/85.
Component and piping configuration for the ECCS's reviewed are documented in Attachment A.
The nomenclature used is in accordance with NUREG/CR-2069.
Surveillance requirements and activities pertaining to the designated high/low pressure isolation valves were reviewed by the inspector.
A summary of the surveillance requirements for each specific isolation valve is included as Attachment B.
The inspector found no discrepancies between Technical Specifications and the guality Assurance Manual specified Inservice Inspection Program requirements.
The implementing station surveillance procedures were reviewed and determined to satisfactorily meet the testing requirements.
The necessary prerequisites, plant con-ditions and amplifying precautions were properly addressed in the governing surveillance procedures.
Station surveillance testing changes made as a result of the April 20, 1981 NRC issued Order For Modification of license and associated imple-menting Technical Specifications, was previously reviewed and documented in Inspection Report No. 50-244/81-11, paragraph 7.
No significant discrepancies were noted in that review.
The inspector determined that, with the exception of infrequent corrective maintenance, all valves listed in Attachment B receive an annual visual inspection to check for degradation and packing leakage.
This annual inspection is conducted in accordance with Administrative Procedure (A)-
1020,
"Valve Preventive Maintenance Program",
Revision 2, dated February 29, 1984.
The inspector did identify two ECCS valves not included on the A-1020 valve list and brought this to the attention of the licensee.
The licensee is initiating a procedural change notice to correct this adminis-trative oversigh The inspector reviewed a sampling.of the special inspection and preventive/corrective maintenance procedures utilized by the licensee and determined that adequate prerequisites and precautions were identified and proper retesting performed.
All of the maintenance procedures reviewed specified the assignment of a guality Control inspector.
Likewise, surveillance procedures specify notification of station guality Control personnel for coverage of the evolution.
A review of station records and interviews with various station personnel determined that there have been no instances of actual or potential ECCS overpressurization in the station's operating history.
The licensee did receive NRC IE Notice No. 84-74, however, did not conclude the problems identified in the Notice to be applicable to Ginna Station systems or procedures.
The inspector interviewed plant staff, licensed operators, surveillance and maintenance technicians and determined that no specific training has been presented with respect to recent industry experience with ECCS isolation valves.
Those individuals interviewed, however, were generally cognizant of precautions and prerequisites associated with maintenance and surveillance testing of RCS/ECCS isolation valves.
The inspector had no further questions.
7.
Licensee Event Re ort LER's The inspector reviewed the following LER'
to verify that the details of the event were clearly reported, the description of the cause was accurate, and adequate corrective action was taken.
The inspector also determined whether further information was required, and whether generic implications were involved.
The inspector further verified that the reporting requirements of Technical Specifications and station administrative and operating procedures had been met; that the event was reviewed by the Plant Operations Review Committee and that continued operation of the facility was conducted within the Technical Specification limits.
85-02:
"Manual Actuation of Engineered Safety Feature".
Due to a decrease in grid frequency on the morning of January 21, 1985, station operators started and loaded both Emergency Diesel Generators as required by station procedures.
This event was reviewed and documented in detail in Inspection Report No. 50-244/85-02, paragraph 3.a.
'I 85-04:
"Automatic Actuation of Engineered Safety Feature (ESF)".
On March 26, 1985 at 10:21 A.M. and 11:25 A.M. inadvertent safety injection actuations were generated while the reactor was in a cold shutdown condition.
The first actuation was generated by 2 of 3 high containment vessel pressure bistable trips.
One containment pressure channel bistable was tripped procedurally for work being conducted on Reactor Protection Channel No.
3.
The second pressure bistable tripped inadvertently due to a momentary loss of power to vital Bus 14 while transferring from its
i r
\\ I lf
N normal electrical power source to an alternate source in preparation for maintenance on the Bus 14 undervoltage relay system.
The licensee determined that the root cause of this safety injection actuation was a
procedural deficiency.
The maintenance procedure did not specify the necessary precautions to be taken for the anticipated interruption in power to Bus 14.
The inspector verified procedural changes were made to ensure safeguards logic trains are not defeated during bus transfers.
The second safety injection (SI) actuation resulted from another momentary power loss to Bus 14 while removing the 1A Diesel Generator feed to Bus 14, (tied in to the safeguards bus as a result of the first SI signal),
and restoring the normal power source to Bus 14.
The SI signal was generated when a
2 of 3 logic unblock was satisfied for pressurizer pressure being greater than 2000 psig coincident with steamline pressure less than 514 psig.
One unblock relay was already tripped in accordance with procedures governing Reactor Protection Channel 83 work.
The second unblock relay tripped on the momentary power loss.
Again, the licensee determined procedural inadequacies as the root cause.
The inspector discussed this event with licensee management and determined that a shared concern was addressed for multiple outage activities potentially overburdening the control room operators.
Control room operators were instructed to more carefully screen scheduled work activities for potential conflicts and have been given greater authority to stop specific work items if deemed necessary for continued safe and controlled plant operations.
85-05:
"Automatic Actuation of Reactor Protection System"
~
On April 5, 1985 an inadvertent reactor trip signal was generated while the reactor was in the Hot Shutdown mode.
The reactor trip breakers, which were closed in preparation for plant start-up, opened as designed.
The cause and details of this event were reviewed and documented in Inspection Report 50-244/85-06, paragraph 3.c.2.
85-06:
"Automatic Actuation of the Reactor Protection System".
At 7:02 P.M.
on April 6, 1985, the reactor tripped from approximately five percent power due to low +B'team generator level (30%) coincident with a manually tripped steam/feedwater flow mismatch bistable.
The steam/feedwater flow mismatch bistable was tripped in accordance with a feedwater flow instrument calibration procedure in progress.
The steam generator water levels were being controlled manually at the time of the trip and the operator was unable to maintain the narrow 30% to 39% level control band while the turbine was being brought up to synchronous speed.
85-07:
"Automatic Actuation of the Reactor Protection System".
At 11:41 P.N. April 6, 1985, the reactor tripped from approximately 12 percent power due to +B'team generator low-low level (17%).
The details of this event were reviewed and documented in Inspection Report 50-244/85-06 paragraph ~
h
'
85-08:
"Automatic Actuation of the Reactor Protection System".
At 10:39 A.M. April 7, 1985, the reactor tripped from approximately 13 percent power due to +A'team generator low-low level (17%).
The details of this event were reviewed and documented in Inspection Report 50-244/85-06 paragraph 3.a.
85-09:
"Automatic Actuation of the Reactor Protection System".
At 5:36 A.M. April 8, 1985, the reactor tripped from approximately 18 percent power due to a condensate system perturbation which caused the one operating main feedwater pump to trip, a turbine trip and consequently low-low steam generator level reactor trip.
The details of this event were reviewed and documented in Inspection Report 50-244/85-06, paragraph 3.a.
85-10:
"Automatic Actuation of Reactor Protection System".
At 9:45 A.M.
April 8, 1985, the +B'eactor trip breaker tripped open while conducting an operational test of Nuclear Instrumentation System (NIS) Intermediate Range Channel N-35.
The'eactor was in Hot Shutdown mode with shutdown bank rods at 50 steps and being withdrawn in accordance with the plant start-up procedure.
All rods fully inserted when the +B'eactor trip breaker opened.
Investigation by the licensee determined that a faulted relay for NIS Source Range Channel N-31 was the cause of the +B'eactor trip breaker opening.
Troubleshooting determined that the +B'eactor protection train N-35 and N-31 trip relays are physically located adjacent to one another.
When the channel N-35 variable test signal reached the level trip bistable setpoint, in accordance with the applicable step of the test procedure, the actuation of the associated
+B'eactor protection train trip relay caused a momentary opening of the N-31 trip relay contacts and consequently resulted in the +B'eactor trip breaker opening.
This
+chattering'f the N-31 trip relay contacts was duplicated and witnessed by the inspector.
The licensee subsequently replaced the faulted channel N-31 relay and completed the necessary retests for both nuclear instrument channels.
85-11:
"Automatic Actuation of the Reactor Protection System".
At 12:20 P.M. April ll, 1985 the reactor tripped from approximately 8 percent power as a result of a low condenser vac'uum condition.
The low vacuum condition was caused by condenser circulating water gross inleakage.
The details of this event were reviewed and documented in Inspection Report 50-244/85-06, paragraph 3.a.
85-12:
"Inoperable Containment Charcoal Filters".
On May 6, 1984, as a
result of an engineering evaluation of the effectiveness of iodine removal by the containment air recirculation-charcoal filtering system, the licensee's engineering staff determined that the system could be rendered inoperable under large break Loss of Coolant Accident (LOCA) conditions.
It was postulated that portions of the charcoal filter discharge duct work located in the basement of containment could be flooded after the
ir t
Refueling Water Storage Tank (RWST) had emptied its contents through the LOCA break.
To circumvent this potential problem, the licensee h'as removed access ports, pinned open implosion dampers and fabricated an additional opening on the 1B filter discharge duct work to insure sufficient air flow for filtration, mixing and cooling of the containment atmosphere.
The inspector closely.monitored licensee engineering and plant staff activities associated with this event.
The
CFR 50.59 safety evaluation accompanying the modification to the charcoal filter discharge duct work was reviewed and discussed with the licensee.
No deficiencies were noted.
The inspector determined that no further modification of the containment air recirculation system charcoal filtering di scharge duct work is planned, however, engineering's iodine removal efficiency evaluation is still ongoing.
The inspector had no further questions.
8.
Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9. 1 and 6.9.3 were reviewed by the inspector.
This review included the following considerations:
the reports contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the validity of the reported information.
Within the scope of the above, the following reports were reviewed by the inspector:
Monthly Operating Reports for April and May 1985.
9.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection, scope and findings.
Based on the NRC Region I review of this report and discussion held with licensee representatives on June 18, 1985, it was determined that this report does not contain information subject to
CFR 2.790 restriction Attachment A
Interface S stem:
Safety Injection, Loop A-Hot Leg flow direction:
IN component Lineup:
RCS-2CK-H/L-MOV-I-MV-CK-P LC LO Low press:
1501 High press:
2501 Interface S stem:
Residual Heat Removal, Loop A-Hot Leg flow direction:
OUT component Lineup:
RCS-MOV-MOV-H/L-I-MOV-P PRINL LC NO Low press:
601 High press:
2501 Interface S stem:
Safety Injection, Loop A-Cold Leg flow direction:
IN component Lineup:
RCS-2CK-H/L-MV-MOV-I-MV-CK-P NO LO LO Low press:
1501 High press:
2501 component lineup:
Low press:
902 High press:
2501 RCS-2CK-H/L-MOY-Accum.
LO Interface S stem:
Accumulator ¹2, Loop A-Cold flow direction:
IN Note:
Leg Same RCS penetration as Safety. Injection Loop A above, with common check (8678)
Interface S stem:
Safety Injection, Loop 8-Cold Leg flow direction:
IN component lineup:
RCS-2CK-H/L-MOY-I-MV-CK-P LO LO Low press:
1501 High press:
2501
Attachment A
Interface S stem:
Accumulator 81, Loop, 8-Cold Leg flow direction:
IN Note:
Same RCS penetration as Safety Injection Loop 8 above, with common check (867A)
component lineup:
RCS-2CK-MOV-Accum.
LO Low press:
902 High press:
2501 Interface S stem:
flow direction:
component lineup:
Interface System flow direction:
component lineup:
Low press:
1501 High press:
2501 Interface S stem flow direction:
component lineup:
Low press:
601 High Press:
2501 Residual Heat Removal, Loop 8-Cold Leg IN Note:
Same RCS penetration as Safety Injection Loop 8 above RCS-MOV-MOV-H/L-I-MV-BFV-HX-MV-MV-P PRINL LC LO NO LO Safety Injection, Loop 8-Hot Leg IN RCS-2CK-H/L-MOV-I-MV-CK-P LC LO Residual Heat Removal Reactor Vessel Deluge IN RCS-CK-MOV-H/L-I-MV-BFV-HX-2MV-CK-P NC LO NO RCS-CK-MOV-H/L-I-MV-BFV-HX-2MV-CK-P NC LO NO Note:
Common piping through containment penetration
1
Valve No.
Descrip-tion ISI
~Cate or ATTACHMENT B Test
~Fre
.
~Re
.
Procedure 842 A&B 852 A&B 853 A&B 8" check 6" gate 6" check 877 A&B 878 F
878 G
2" check 2" check 2" check 878 H
878 J 2" check 2" check 700 701 720 721 Notes:
10" gate 10" gate 10" gate 10" gate 867 A&B 10" check B
A Stroke Leak Stroke Stroke Leak Stroke Leak Leak Leak Stroke Leak Leak Stroke Leak Stroke Stroke Stroke Stroke C/R ISI C/R 'SI C/R ISI C/R ISI C/R ISI/T.S.
4.3.3.1 C/R ISI C/R ISI/T.S.
4.3.3.1 40mo.
IS I/T.S.
4.3.3.3 40mo.
IS I/T.S.
4.3.3.3 R
ISI/T.S.
4.3.3.1 C/R ISI/T.S.
4.3.3.2 40mo.
IS I/T.S.
'.3.3.3 R
ISI/T.S.
4.3.3.1 C/R
, ISI/T.S.
4.3.3.2 C/R ISI C/R ISI C/R ISI C/R ISI PT-2. 1 PT-2.1 PT-2.4 PT-2. 10. 2 PT-2. 10. 4 PT-2. 10. 1 PT-2. 10. 4 PT-2. 10. 4 PT-2. 10. 4 PT-2. 1 PT-2. 10.4 PT-2. 10. 4 PT-2. 1 PT-2
~ 1 PT-2. 10. 4 PT-2.4. 1 PT-2. 4. 1 PT-2.4. 1 PT-2.4. 1 C/R cold shutdown and refueling R - refueling outage ISI - inservice inspection program - Ginna gA Manual Appendix C
PT Ginna Station Periodic Test (surveillance test)
ISI Category A valves for which seat leakage is limited to a
specific maximum amt.
in the closed position for fulfillment of their function ISI Category B - valves for which seat leakage in the closed position is inconsequential for fulfillment of their function
<1