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{{Adams | |||
| number = ML20129B291 | |||
| issue date = 06/28/1985 | |||
| title = Insp Rept 50-333/85-09 on 850401-0531.No Violation Noted. Concern Expressed Re Failure to Implement Mod in Containment Atmosphere Dilution Sys to Protect Carbon Steel Nitrogen Makeup Lines from Low Temp Brittle Fracture | |||
| author name = Linville J | |||
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) | |||
| addressee name = | |||
| addressee affiliation = | |||
| docket = 05000333 | |||
| license number = | |||
| contact person = | |||
| document report number = 50-333-85-09, 50-333-85-9, NUDOCS 8507150483 | |||
| package number = ML20129B279 | |||
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS | |||
| page count = 21 | |||
}} | |||
See also: [[see also::IR 05000401/2005031]] | |||
=Text= | |||
{{#Wiki_filter:, | |||
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U.S. NUCLEAR REGULATORY COMMISSION | |||
REGION I | |||
DCS Numbers | |||
50-333-850322 | |||
50-333-850418 | |||
50-333-850421 | |||
50-333-850503 | |||
50-333-850220 | |||
50-333-850506 | |||
Report No. 85-09 | |||
Docket No. 50-333 | |||
License No. OPR-59 Priority -- | |||
Category C | |||
Licensee: Power Authority of the State of New York | |||
P.O. Box 41 | |||
Lycoming, New York 13093 | |||
Facility Name: J.A. FitzPatrick Nuclear Power Plant | |||
Inspection At: Scriba, New York | |||
Inspection Conducted: April 1, - May 31, 1985 | |||
Inspectors: | |||
L.T. Doerflein, Senior Resident Inspector | |||
W.J. Lazarus, Senior Emergency | |||
Preparedness Specialist | |||
A.J. Luptak, Resident Inspector, NMP-1 | |||
Approved by: | |||
J | |||
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C. Linv1 TTe', Chief,/%f actor | |||
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rojects Section 2C V | |||
' Inspection Summary: | |||
Inspection on April 1, - May 31, 1985 | |||
(Report No. 50-333/85-09) | |||
Areas Inspected: Routine and reactive inspection during day and backshift hours | |||
by two resident inspectors and one region based inspector (200 hours) of | |||
licensee action on previous inspection findings, licensee' event report review, | |||
operational safety verification, survelliance observations, maintenance | |||
observations, plant startup from refueling, determination of reactor shutdown | |||
- margin, startup testing of the Analog Transmitter Trip System, followup on | |||
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licensee response to GE Service Information Letter No. 402, review of the | |||
Emergency Core Cooling Systems subject to potential overpressurization, follow- | |||
up on licensee event, relocation of the Emergency Operations Facility and | |||
review of periodic and special reports. | |||
Results: No violations were identified in the areas inspected. | |||
However, as discussed in paragraph 10, we are concerned about the failure to | |||
implement a modification on the Containment Atmosphere Dilution System to | |||
protect the carbon steel nitrogen makeup lines from low temperature brittle | |||
fracture. The significance of this modification was highlighted by the | |||
failure of the vent header.at another facility, during the past year, due to | |||
improper operation of the nitrogen inerting system. We are also concerned | |||
that this maybe indicative of a general lack of progress in reducing the | |||
modification backlog identified in inspection report 50-333/82-24. | |||
The continuing problems with pilot valve seat leakage and setpoint drift of | |||
the target Rock safety relief valves (discussed in paragraph 3) renew concerns | |||
regarding the need for increased management attention in pursuing resolution | |||
of these problems. | |||
Other concerns involving Source Range Monitor and Intermediate Range Monitor | |||
instrument dry tube cracking, the Shutdown Margin demonstration, and the | |||
inadvertent lifting of a fuel bundle from the reactor core are documented in | |||
paragraphs 6., 8., and 12. respectively. | |||
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DETAILS | |||
1. Persons Contacted | |||
*R. Baker, Technical Services Superintendent | |||
V. Childs, Senior Licensing Engineer | |||
*R. Converse, Superintendent of Power | |||
M. Curling, Training Superintendent | |||
*W. Fernandez, Operations Superintendent | |||
*H. Glovier, Resident Manager | |||
H. Keith, Instrument and Control Superintendent | |||
D. Lindsey, Assistant Operations Superintendent | |||
R. Liseno, Maintenance Superintendent | |||
*E. Mulcahey, Radiological & Environmental | |||
Services Superintendent | |||
R. Patch, Quality Assurance Superintendent | |||
T. Teifke, Security & Safety Superintendent | |||
The inspector also interviewed other licensee personnel during this | |||
inspection including shift supervisors, administrative, operations, health | |||
physics, security, instrument and control, maintenance and contractor | |||
personnel. | |||
* Denotes those present at the exit interview. | |||
2. Licensee Action on Previous Inspection Findings | |||
(0 pen) Unresolved Item (333/77-26-06): In a letter dated November 14, | |||
1977, the architect-engineer indicated that the Containment Atmosphere | |||
Dilution System logic would be modified to provide low temperature pro- | |||
tection for the carbon steel nitrogen makeup lines. The inspector noted | |||
that this modification has not been implemented. Additional details on | |||
this item are discussed in paragraph 10. of this report. | |||
(0 pen) Inspector Followup Item (333/83-04-03): The inspector noted that | |||
the licensee continues to have problems with setpoint drift on the two | |||
stage Target Rock safety relief valves. Additional details on this item | |||
are discussed in paragraph 3. of this report. | |||
3. LicenseeEventReport(LER) Review | |||
The inspector reviewed LER's to verify that the details of the events were | |||
clearly reported. The inspector determined that reporting requirements | |||
had been met, the report was adequate to assess the event, the cause | |||
appeared accurate and was supported by details, corrective actions | |||
appeared appropriate to correct the cause, the form was complete and | |||
generic applicability to other plants was not in question. | |||
LER's 85-09*, 85-10*, 85-11, 85-12, 85-13* were | |||
, | |||
reviewed. | |||
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*LER's selected for onsite followup. | |||
LER's 85-09 and 85-13 reported that, when tested, a total of five Target | |||
Rock two stage safety relief valves had setpoints outside the Technical | |||
Specification allowable tolerance. The vendor believes that the possible | |||
causes of this setpoint drift are inadequate clearances in the laberinth | |||
seal area and pilot valve seat leakage. The vendor is paying particular | |||
attention to laberinth seal clearance during valve overhaul. The licensee | |||
was also informed by the vendor that the pilot seat leakage could be | |||
caused by testing the valves at to low a steam pressure such that the | |||
pilot valve doesn't have any cushion effect when shutting. As a result, | |||
the licensee revised the surveillance procedure to increase the test | |||
pressure to 250-300 psig. However, despite this change, following safety | |||
relief valve testing during the startup from the 1985 refueling outage, | |||
the licensee noted indications of pilot seat leakage on the "F" safety | |||
relief valve. The inspector will continue to review licensee's progress | |||
in resolving the safety relief valve drift during a subsequent inspection. | |||
LER 85-10 reported that a fuel bundle was inadvertently lifted from the | |||
reactor core when it was caught on one of the lock levers of the fuel | |||
support grapple. Details of this event are discussed in paragraph 12. of | |||
this report. | |||
4. Operational Safety Verification | |||
a. Control Room Observations | |||
Daily, the inspectors verified selected plant parameters and equip- | |||
ment availability to ensure compliance with limiting conditions for | |||
operation of the_ plant Technical Specifications. Selected lit | |||
annunciators were discussed with control room operators to verify | |||
that the reasons for them were understood and corrective action, if | |||
required,' was being taken. The inspectors observed shift turnovers | |||
biweekly to ensure proper control room and shift manning. The | |||
inspectors directly observed the operations, listed below to ensure | |||
adherence to approved procedures: | |||
f | |||
-- | |||
Reactor startup on May 28, 1985. | |||
-- | |||
Issuance of RWP's and Work Request / Event / Deficiency forms. | |||
No violations'were identified, | |||
b. Shift loos ~ and Operating Records | |||
Se'locted shif t logs and operating records were reviewed to obtain | |||
information on plant problems and operations, detect changes and | |||
trends in performance, detect possible conflicts with Technical | |||
e | |||
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Specifications or regulatory requirements, determine that records are | |||
being maintained an'd reviewed as required, and assess the effective- | |||
ness of the communications provided by the logs. | |||
No violations-were identified, | |||
c . Plant Tours | |||
During the inspection period, the inspectors made observations and | |||
conducted tours of the plant. During the plant tours, the inspectors | |||
conducted a visual inspection of selected piping between containment | |||
and the isolation valves for leakage or leakage paths. This included | |||
verification that manual valves were shut, capped and locked when | |||
required and that motor operated valves were not mechanically | |||
blocked. The inspectors also checked fire protection, house- | |||
keeping / cleanliness, radiation protection, and physical security | |||
conditions to ensure compliance with plant procedures and regulatory | |||
requirements. | |||
No violations were identified. | |||
d. Tagout Verification | |||
The inspector verified that the following safety-related | |||
protective tagout records (PTR's) were proper by | |||
observing the positions of breakers, switches and/or valves. | |||
-- | |||
PTR 850548 on "C" Residual Heat Retraval Service Water System. | |||
-- | |||
PTR 850572 on "B" Station Battery Charger. | |||
-- | |||
PTR 850603 on the Reactor Protection System. | |||
-- | |||
PTR-850647 on the "A" Emergency Service Water System. | |||
-- | |||
PTR 850783 on the "B" Residual Heat Removal System. | |||
-- | |||
PTR 850858 on the "B" Residual Heat Removal Service Water | |||
System. | |||
No violations were identified. | |||
5. ' Surveillance Observations | |||
The inspector observed portions of the surveillance procedures listed | |||
below to verify that the test instrumentation was properly calibrated, | |||
approved procedures were used, the work was performed by qualified per- | |||
sonnel, limiting conditions for operation were met, and the system was | |||
correctly restored following the testing: | |||
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F-ST-398, Type "B" and "C" LLRT of Containment Penetrations, | |||
Revision 14, dated March 20, 1985, performed April 8, 9 and 15, | |||
1985. | |||
-- | |||
F-ST-29E, Backup Scram Valves Functional Test, Revision 0, | |||
dated February 27, 1985, performed April 19, 1985. | |||
-- | |||
F-ST-39L, Reactor Vessel Hydrostatic Test, Revision 0, dated | |||
May 1, 1985, performed May 7, 1985. | |||
-- | |||
F-ISP-1, Instrument Line Flow Check Valve Operability Test, | |||
Revision 5, dated June 18, 1981, performed May 8, 1985. | |||
-- | |||
F-ST-16I, 125 VDC Station Battery Service Discharge and | |||
Charger Performance Test, Revision 1, dated April 27, 1983, | |||
performed May 17, 1985. | |||
-- | |||
F-ST-290, Integrated Scram System Test, Revision 2, dated | |||
January 23, 1985, performed May 31, 1985. | |||
-- | |||
F-ST-5N, APRM Instrument Functional Test (Refuel, Startup, | |||
Shutdown Mode), Revision 7, dated October 31, 1984, performed May | |||
, 31, 1985. | |||
The observations of the Local Leak Rate Testing (LLRT). included the post | |||
maintenance LLRT on the repaired Reactor Water Cleanup inboard contain- | |||
ment isolation valve (12-MOV-15) and the "B" Feedwater outboard contain- | |||
ment isolation valve (34-NRV-1118). The inspector noted that 12-M0V-15 | |||
passed the LLRT while 34-NRV-111B failed and had to be reworked. The | |||
inspector also noted that 34-NRV-111B had to be reworked several times | |||
before successfully passing an LLRT. As discussed in paragraph 6. of this | |||
report, the inspector witnessed a portion of the maintenance performed on | |||
34-NRV-1118. Based on these observations and discussions with licensee | |||
personnel, the inspector determined that the licensee adequately performed | |||
retesting (LLRT) on repaired containment isolation valves. | |||
No violations were identified. | |||
6. Maintenance Observations | |||
a. The inspector observed portions of various safety-related maintenance | |||
activities to determine that redundant components were operable, | |||
these activities did not violate the limiting conditions for opera- | |||
tion, required administrative approvals and tagouts were obtained | |||
prior to initiating the work, approved procedures were used or the | |||
activity was within the " skills of the trade," appropriate radio- | |||
logical controls were properly implemented, ignition / fire prevention | |||
controls were properly implemented, and equipment was properly tested | |||
prior to returning it to service. | |||
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b. During this inspection period, the following activities | |||
were observed: | |||
-- | |||
WR 00/21073 on the functional testing of safety related | |||
snubbers | |||
-- | |||
WR 07/38673 on the replacement of "D" Intermediate Range | |||
Monitor dry tube. | |||
-- | |||
WR 34/35562 on the repair of "B" Feedwater Outboard | |||
Containment Isol.cion Check Valve. | |||
-- | |||
WR 46/25455 on the repair of the "A" Emergency Service Water | |||
Pump discharge check valve. | |||
-- | |||
WR 71/22674 on the replacement of "A" Low Pressure Coolant | |||
Injection System Battery | |||
-- | |||
F-IMP-71.18B on the post maintenance testing of replaced HFA | |||
relays. | |||
c. During the 1985 refueling outage in-vessel Inservice Inspection (ISI) | |||
visual examinations, the licensee identified cracks in all twelve | |||
Source Range Monitor (SRM) and Intermediate Range Monitor (IRM) | |||
instrument dry tubes. The cracks were all in the upper portion of | |||
the dry tube and were similar to those observed at other BWR's and | |||
discussed in General Electric Service Information Letter (SIL) ido. | |||
409. The indications are believed to be the result of Irradiation | |||
Assisted Stress Corrosion Cracking (IASCC). The inspector observed | |||
portions of the videotape containing the dry tube examinations. The | |||
inspector noted that the licensee individual performing the evalua- | |||
tions was qualified as a Level III inspector. | |||
The dry tube ISI results were also evaluated by General Electric (GE) | |||
who concluded that the licensee could operate one additional cycle | |||
with the existing dry tubes with no adverse impact on safety. How- | |||
ever, GE recommended that five of the dry tubes be replaced. Based | |||
on this recommendation, the licensee replaced the dry tubes at core | |||
locations 12-9, 28-33, 36-9, and 36-25 (IRM H, D, G and SRM C) which | |||
had possible indications below the bottom tube weld at the primary | |||
pressure boundary and the dry tube at 28-25 (IRM E) which had a | |||
noticeable bend at the crack location. The licensee also had to | |||
replace the dry tube at 12-33 (SRM A) after the top portion broke off | |||
when it was bumped by a double blade guide during core alterations. | |||
The inspector noted that the licensee recovered the piece which broke | |||
off. | |||
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The inspector noted that the replacement dry tubes were the same | |||
design as the original dry tubes and therefore subject to IASCC. | |||
General Electric in'dicated that a dry tube with materials less | |||
susceptable to IASCC would be available in the near future. The | |||
licensee tentatively plans on replacing the remaining six cracked | |||
dry tubes with ones of the new design during the next refueling | |||
outage and on replacing the six dry tubes just installed during the | |||
following outage to resolve the problem with dry tube cracking. | |||
No violations were identified. | |||
7. Plant Startup from Refueling | |||
The inspectors witnessed portions of the plant startup conducted May 28- | |||
31, 1985 to verify that: the startup was performed in accordance with | |||
approved procedures; surveillance tests required to be performed | |||
prior to startup were satisfactorily completed; systems were properly | |||
aligned prior to startup; the control rod withdrawal sequence was avail- | |||
able; and startup activities were conducted in accordance with Technical | |||
Specification requirements. | |||
No violations were identified. | |||
8. Shutdown Margin Demonstration | |||
The inspector observed the Shutdown Margin (SDM) demonstration performed | |||
on May 6, 1985. The test utilized the diagonally adjacent rod method and | |||
was performed in accordance with an approved procedure. The inspector. | |||
noted that the licensee terminated the test with the margin rod (22-27) at | |||
notch position 12 and the object rod (26-31), the analytically determined | |||
highest reactivity worth control rod, at position 36 after Source Range | |||
Monitor (SRM) count rate went from 60 counts per second (cps) to approxi- | |||
mately 200,000 cps during the test. The procedure required the object rod | |||
to be fully withdrawn. Using data obtained during the test, the fuel | |||
vendor determined the SDM to be .54% AK/K. The Technical Specifications | |||
required that the SDM for Cycle 7 be greater than .44%_AK/K. However, due. | |||
to the unusual increase in SRM count rate during the test and because the | |||
calculated SDM was significantly below the SDM design value of 1.17% AK/K, | |||
additional NRC inspections by regional specialists were conducted to | |||
evaluate the results of the tests. | |||
As part of his followup to the SDM test, the resident inspector reviewed | |||
the completed core verification maps prepared by the licensee and noted | |||
that the final verified position of the fuel bundles was in accordance | |||
with the FitzPatrick Cycle 7 Management Report dated April 1985. The | |||
inspector noted that the verification had been performed by a Reactor | |||
Engineer and a licensed operator. A separate review of the videotapes was | |||
conducted by two Quality Control (QC) inspectors. Following the SDM test, | |||
two additional QC inspectors performed another review of the core veri- | |||
fication videotapes. The resident inspector also viewed the core | |||
. | |||
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verification videotapes and verified, for a sample of one half the core, | |||
that the fuel bundle position and orientation were in accordance with the | |||
core map. The videotapes were generally clear and the serial numbers on | |||
the fuel assemblies were adequately visible. No discrepancies were | |||
identified. | |||
On May 25, 1985, the licensee performed a SDM demonstration using the | |||
in-sequence critical method to verify adequate SDM before the startup | |||
from the refueling outage. The inspector reviewed the test results | |||
obtained in accordance with the licensee's procedure and noted that the | |||
calculated SDM with the strongest control rod fully withdrawn was .79% | |||
AK/K. During the plant startup on May 28, 1985, another in-sequence | |||
critical demonstration resulted in a calculated SDM of .81% AK/K. | |||
Based on the data reviewed, the inspector determined that the demonstrated | |||
SDM met the Technical Specification requirements. Based on a review of | |||
correspondence with the fuel vendor and on di!cussions with licensee | |||
personnel, the inspector noted that the deviations between the calculated | |||
SDM and the design values are probably due to calculational uncertainties. | |||
Additional details on the evaluation of the SDM demonstrations are docu- | |||
mented in inspection reports no. 50-333/85-14 and 50-333/85-17. | |||
9. Startup Testing-Analog Transmitter Trip System | |||
The inspector reviewed portions of preoperational procedure no. Misc. 02A, | |||
"Preoperational Test of Analog Transmitter / Trip System for RPS and ECCS | |||
Sensor Trip Inputs (Mod. No. F1-82-53)", Revision 1, dated April 24, 1985, | |||
to verify that the procedure was properly approved and included: procedure | |||
scope and objectives; prerequisities; precautions; acceptance criteria; | |||
checkoff lists; reference to drawings and applicable procedures; pro- | |||
visions for recording details of the conduct of the test; provision for | |||
identification of personnel conducting the testing and evaluation of test | |||
data; and provision for quality control verification of critical' steps. | |||
The inspector also verified that changes to the preoperational procedure | |||
were reviewed as required by Technical Specifications. | |||
The inspector also witnessed portions of the testing and verified that the | |||
test was conducted in accordance with the approved procedure and that | |||
quality control verification was performed during the test. For the | |||
testing observed, the inspector noted that the test results were within | |||
the previously established acceptance criteria. | |||
No violations were identified. | |||
10. Followup on licensee response to General Electric Service | |||
Information Letter (SIL) No.402, Wetwell/Drywell Inerting | |||
, Based on discussions with licensee personnel and a review of Operating | |||
Experience Report No. 185, the inspector verified that the licensee eval- | |||
uated the design and operation of the liquid nitrogen based inerting | |||
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system as recommended by General Electric SIL No. 402. The evaluation was | |||
performed by the Performance and Reliability Department in accordance with | |||
procedure PS0 28, " Operating Experience Feedback," and identified problems | |||
with the operation and testing of the liquid nitrogen inerting system. | |||
The inspector reviewed procedures F-0P-37, " Nitrogen Ventilation and | |||
Purge; Containment Atmosphere Dilution (CAD); Containment Vacuum | |||
Relief and Containment Differential Pressure Systems," Revision 20, and | |||
F-ST-25A, " Nitrogen System Low Temperature Simulated Automatic Isolation | |||
Functional Test," Revision 0, and determined that, in response to these | |||
findings, the licensee revised or developed procedures to verify proper | |||
operation of the nitrogen inerting system automatic isolation prior to | |||
inerting the containment and to add cautions on system monitoring if the | |||
automatic isolation . valves are bypassed, such as during containment | |||
inerting directly from a nitrogen truck. The inspector also reviewed | |||
calibration data sheets dated October 2,1984 to verify that the tempera- | |||
ture sensors used for nitrogen system monitoring and for the automatic | |||
isolation functions were properly calibrated. The inspector verified that | |||
these sensors have been added on the calibration schedule to ensure | |||
periodic recalibration. | |||
The inspector also noted that, during the evaluation, the licensee | |||
reviewed the portions of the liquid nitrogen system used for containment | |||
makeup during normal operations. This review noted that a modification | |||
was proposed by the architect-engineer in a letter dated November 14, | |||
1977, to resolve a deficiency identified in Inspection Report No. | |||
50-333/77-26 concerning the lack of low temperature isolation protection | |||
for the carbon steel nitrogen makeup lines in case of a loss of the elec- | |||
tric heater downstream of the ambient vaporizers._ Based on discussions | |||
with licensee personnel, the inspector found that this modification had | |||
not been implemented. The inspector expressed concern that no action had | |||
.been taken on this problem for so long. The' licensee acknowledged the | |||
inspector's concern and stated that after the refueling outage emphasis | |||
would be placed on identifying and completing these old moficiations. The | |||
inspector will review licensee progress in this area during future | |||
inspections. | |||
The inspector reviewed the completed data sheets for procedure F-ST-39E, | |||
"Drywell to Suppression Chamber Vacuum Breaker Leak Test," performed on | |||
February 15, 1985. The purpose of this procedure is to determine the | |||
total equivalent bypass area leakag'e (normally expected through the vacuum | |||
breakers) between the Drywell and Suppression Pool. The test consists of | |||
maintaining a specified differential pressure (1.0 psid) between the | |||
Drywell and Suppression Pool and monitoring the rise in Suppression Pool | |||
pressure over a ten minute period. The inspector noted that the results | |||
of.the test were satisfactory and there were no indications of bypass | |||
leakage. As discussed in paragraph 6. of Inspection Report No. 50-333/- | |||
84-18, the inspector has previously determined that the licensee reviewed | |||
plant data and concluded that there were no anomalies which could be | |||
indicative of Suppression Pool vent header cracks. The inspector had also | |||
previously reviewed Quality Control Inspection Report No. F84-057, which | |||
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documented the visual inspections performed on portions of the vent | |||
header, both inside and outside, including the nitrogen penetration to | |||
suppression pool shell weldment. No cracks were.found during these visual | |||
inspections. The inspector noted that no ultrasonic testing of the | |||
nitrogen penetration was performed due to lack of baseline data. | |||
Based on his review, the inspector concluded that the licensee implemented | |||
the recommendations of SIL No. 402 regarding vent header cracking. As | |||
noted above, the inspector's only concern was the licensee's failure to | |||
implement the modification needed to provide low. temperature isolation | |||
protection for the nitrogen makeup lines. | |||
11. Review of Emergency Core Cooling Systems Subject | |||
to Potential Overpressurization | |||
The inspectors reviewed records and procedures and held discussions with | |||
licensee personnel to evaluate the design features and administrative | |||
controls that are used to minimize the potential for Emergency Core | |||
Cociing System (ECCS) overpressurization. | |||
~ | |||
a. Verification of as-built isolation interfaces | |||
The inspectors reviewed various drawings and Stone and Webster Line | |||
Designation Tables to identify those systems which contain components | |||
or piping with design pressures equal to or less than 70% of the | |||
design pressure of the primary coolant system. The inspectors noted | |||
that the High Pressure Coolant Injection (HPCI), Reactor Core Isola- | |||
tion Cooling (RCIC), Residual Heat Removal (including the Low | |||
Pressure Coolant Injection (LPCI) and Shutdown Cooling / Head Spray | |||
Modes), and Core Spray (CS) Systems all contain such high/ low | |||
pressure interfaces. Additional details on the component configur- | |||
ation and the design high and low pressures can be found in attach- | |||
ment A to this report. | |||
The inspectors also.noted that, with respect to these systems, LPCI, | |||
l CS, HPCI and RCIC all have testable check valves (valves 10-A0V-68A | |||
i and B, 14-A0V-13 A and B, 23-A0V-18, and 13-A0V-22 respectively). | |||
! | |||
The air operators on these valves are maintained operable and are | |||
used only during cold shutdown to verify operability of the check | |||
valve as required by Technical Specifications. | |||
The inspectors determined that for each of the systems with a test- | |||
able check valve, the air operated check valve (A0V) and the first | |||
motor operated valve (MOV) (a normally closed valve) upstream of the | |||
A0V provide isolation for the high and low pressure interface. The | |||
second MOV (a normally open valve) upstream of the A0V can also be | |||
i used to provide the isolation function. For Head Spray, the isola- | |||
i tion function is provided by a check valve and the normally closed | |||
l inboard and outboard containment isolation MOV's. For Shutdown | |||
i | |||
C:oling, the isolation function is provided by the normally closed | |||
l inboard and outboard containment isolation MOV's. | |||
I | |||
! | |||
; .. | |||
1 | |||
r - | |||
. | |||
- | |||
- | |||
- | |||
. | |||
. O O | |||
11 | |||
. | |||
The inspectors focused their review of surveillance and maintenance | |||
activities on the " isolation valves" identified above which normally | |||
maintain isolation for each high/ low pressure interface as well as | |||
those valves which could be used to provide the isolation function. | |||
b. Surveillance Activities | |||
The inspectors reviewed the various surveillance test procedures | |||
listed in attachment B and held discussions with licensee | |||
personnel to determine the surveillance activities that apply to | |||
the isolation valves at each high/ low pressure interface. The- | |||
inspectors noted that there are several surveillance tests which | |||
are conducted to test the operation of the isolation valves for | |||
each ECCS system and RCIC. The inspector also noted that, | |||
although there is considerable overlap with ASME Section XI, the | |||
frequency of the tests are usually determined by the Technical | |||
Specifications which are more restrictive. The following is a | |||
summary of the surveillance testing performed on the isolation | |||
valves: | |||
1. A valve operability test is performed once a month to verify | |||
the valves operate correctly when cycled from the control room. | |||
When performing this test on CS or RHR the plant may be at power | |||
or shutdown. For HPCI and RCIC'the plant must be at power with | |||
steam available. | |||
2. A system automatic actuation test is performed once a cycle | |||
by inputing simulated signals and ensuring the systems respond as | |||
appropriate. When performing this test on CS or RHR the plant | |||
must be shutdown and depressurized as the isolation valves are | |||
operated. For HPCI and RCIC the test is performed at power with | |||
the pump discharge lined up to the Condensate Storage Tank and | |||
with the inboard isolation shut and power removed. | |||
L | |||
3. A system logic functional test is performed every six months | |||
by inputing simulated signals and assuring that the system logic | |||
functions properly. The plant may be operating or shutdown when | |||
testing CS or RHR. The plant is at power when testing HPCI and | |||
RCIC. During this test the inboard isolation valve (for each | |||
system) is shut with the power removed. | |||
4. Local Leak Rate Testing is performed on all isolation valves | |||
(except for the HPCI and RCIC testable check valve and outboard | |||
isolation valve) each refueling outage. | |||
5. The CS, RHR, HPCI and RCIC testable check valves are cycled | |||
j each cold shutdown greater than 48 hours if not done within the | |||
! | |||
last 31 days. | |||
; | |||
l | |||
l | |||
, | |||
~ | |||
- | |||
- | |||
~ | |||
. | |||
. O O | |||
12 | |||
The inspectors noted that the preceutions associated with the sur- | |||
veillance tests are.not uniform. Several of the tests contain | |||
precautions concerning opening both isolation valves simultaneously | |||
while a few others caution to ensure steps are followed in proper | |||
sequence. Some of the tests contain no precautions concerning the | |||
isolation valves. The inspectors also noted that the precautions | |||
appear to be concerned with the possibility of injecting water into | |||
the reactor vessel rather than.the potential for ECCS overpressuri- | |||
zation. However, the inspectors determined that the sequence of the | |||
test procedures (consisting of concise, specific, and identifiable | |||
steps each of which requires a verification signature on the data | |||
sheet) minimizes the potential for ECCS overpressurization. | |||
The inspectors also noted that, in some of the tests, the | |||
interlock between the isolation valves for the low pressure ECCS | |||
systems is bypassed when simulated pressure signals are inputed. | |||
Inadvertent valve operation is presented during these tests by | |||
removing power to the valve operators. The inspectors determined | |||
that, if a jumper is installed or an interlock bypassed, the | |||
procedure ensures that the system is returned to normal at the | |||
completion of testing. | |||
The inspectors noted that the training for operators, with respect to | |||
the isolation valves, has basically consisted of. placing industry | |||
information on valve problems (IE Information Notices, INPO SOER's | |||
etc.) in the required reading book. There is no specific training on | |||
the surveillance testing of these violation valves. | |||
c. Maintenance Activities- | |||
The inspectors reviewed maintenance procedures, work requests and | |||
Licensee Events Reports to determine the maintenance activities and | |||
practices that apply to the isolation valves and their operators. | |||
Based on this review and discussions with licensee personnel, the | |||
inspectors noted that, in general, the licensee has not performed | |||
preventive maintenance on the isolation valves. However, the | |||
licensee indicated that a preventive maintenance program for all | |||
safety related motor operated valves (M0V's) would be implemented in | |||
the near future. This program would include items such as changing | |||
grease and checking torque switch settings on a periodic basis. With | |||
the exception of a few failures of valve motors and air operated | |||
solenoid valves, the inspectors noted that the majority of corrective | |||
maintenance on the isolation valves was due to Local Leak Rate Test | |||
failures, body to bonnet and packing leaks, problems with torque | |||
switch settings, and position indication failures. The frequency of | |||
the maintenance varied for the isolation valve involved. | |||
. | |||
i * | |||
s | |||
L | |||
_ _ _ _ - _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ | |||
. | |||
~ p A | |||
. . | |||
. | |||
, | |||
V U | |||
13 | |||
Some valves required very little maintenance while others, such as | |||
the RHR, CS and RCIC testable check valves and both shutdown cooling | |||
isolation valves, required considerable maintenance. | |||
Only one modification (other than environmental qualification | |||
. upgrading) has been completed on these isolation valves. This modi- | |||
fication was. initiated to resolve recurring maintenance problems on | |||
the inboard Shutdown Cooling (SDC) isolation valve and involved | |||
rerouting the SDC line (to provide easy access to the valve for | |||
-maintenance) and installing a new valve. Another recurring problem | |||
has been the failure of the disc position indication on the RHR and | |||
CS testable. check valves (3 out of 4 are currently inoperable). The | |||
licensee has decided not to maintain these indicators operable due to | |||
the frequency of failures and ALARA considerations. As a result the | |||
licensee uses actuator arm and valve stem movement to verify opera- | |||
tion during required surve.illance testing. The licensee has also | |||
recently implemented procedure TOP-72, " Verification of Disk Position | |||
for. CS and RHR Testable Check Valves," to verify these valves | |||
(without position indication) are shut following t,esting by | |||
monitoring the pressure lag across the valve during a reactor | |||
startup. | |||
The inspectors reviewed the maintenance procedures, (listed in | |||
attachment B) used on the isolation valves and determined that | |||
they were adequate. The inspectors noted that there are separate | |||
procedures for maintenance on motor operators, pneumatic valve | |||
operators, check valves, and gate valves. Each procedure contains | |||
Quality Control inspection hold points including in the area of post | |||
maintenance testing. In general, the post maintenance testing | |||
section of each procedure requires cycling the valve several times to | |||
verify proper. actuator and/or valve operation. Following valve main- | |||
* | |||
tenance, the licensee's Work Activity Control Procedures raquire the | |||
operations department to perform any additional testing to verify the | |||
valve meets the Technical Specification requirements (stroke time, | |||
leak rate, etc.) before declaring the valve operable. | |||
Although not related to the industry problems with the isolation | |||
valves, the inspectors noted that maintenance personnel (Electricians | |||
and Mechanics) have received training on valve maintenance from valve | |||
vendors within the last two years. The inspectors noted that the | |||
amount of corrective maintenance on all safety related valves appears | |||
to be declining and the licensee attributes part of it to this | |||
training. | |||
d. Conclusion | |||
The inspectors noted that the licenree has one design feature which | |||
would provide early indication of an ECCS overpressurization. | |||
Specifically, the Core Spray System is annunciated and provides an | |||
alarm (Core Spray System A (B) High Pressure Valve Leakage) if the | |||
! | |||
i | |||
, | |||
' | |||
O | |||
~ | |||
- | |||
. | |||
. | |||
. O | |||
14 | |||
pressure upstream of the inboard injection valve increases to 450 | |||
psig, indicating leakage by the inboard and testable check valves. | |||
In addition, the inspectors noted that, in response to industry | |||
operating experience regarding previous isolation valve problems, the | |||
licensee now has the auxiliary operator monitor and log (shiftly) | |||
HPCI and RCIC casing temperatures which would increase if there was | |||
backleakage through the isolation valves. The auxiliary operators | |||
are also required to tour (at least once per shift) the areas con- | |||
taining the ECCS and RCIC systems to identify and log any abnormal- | |||
ities some of which, such as CS and RHR system relief valve lifting | |||
or excessive pump seal leakage, may be indicative of a backleakage | |||
problem. | |||
Based on the records reviewed and discussions with licensee per- | |||
sonnel, the inspectors determined that there does not appear to have | |||
been any instances of actual overpressurization of the low pressure | |||
ECCS piping or components. The inspectors also determined that the | |||
maintenance and surveillance procedures reviewed appear adequate to | |||
minimize the potential for such an event. | |||
12. Followup on a 1.icensee Event | |||
On April 21, 1985, while preparing to remove a fuel support piece to allow. | |||
uncoupling control rod 10-35 from the refuel floor, the licensee inadver- | |||
tently lifted a fuel bundle (at location 7-36) out of the reactor core. | |||
The operators had just lowered the fuel support grapple, which was | |||
attached to the frame mounted hoist, to the upper grid. When they- | |||
operated the engage button to allow the grapple to pass.through the upper | |||
grid, an air leak developed which obscured the operators' vision. The | |||
grapple was raised to determine the source of the air leak. As it was | |||
being raised the air leak stopped after the operator cycled the engage and | |||
disengage buttons. When vision was restored, the operators noted that a | |||
fuel bundle had been caught on one of the grapple lock levers and had been | |||
lifted completely out of the core. The operators immediately stopped | |||
grapple motion and informed the control room. The inspector noted that, | |||
prior to and during this event, the licensee had the Standby Gas Treatment | |||
System operating and the reactor building ventilation isolated. During | |||
the event the licensee also evacuated unnecessary personnel from the | |||
Reactor Building. Additional supervisory and management personnel | |||
reported to the refuel floor. | |||
The licensee secured the fuel bundle to the refuel bridge using a "J" hook | |||
and rope. The fuel bundle was then raised using the frame mounted hoist- | |||
and transferred to the Spent Fuel Pool. The inspector noted that the | |||
bundle always remained underwater and that there was no change in the | |||
refuel floor radiation readings monitored during the event. When the | |||
bundle was lowered into a rack in the Spent Fuel Pool, it. slipped off the | |||
grapple lock lever and had to be-manually lowered using the "J" hook and | |||
rope. The fuel bundle was subsequently inspected by the licensee and | |||
General Electric personnel and found undamaged. The licensee counseled | |||
. | |||
' | |||
. . | |||
- | |||
_ | |||
. O o | |||
15 | |||
all operators on this event and cautioned them to immediately stop all | |||
in-vessel operations when visual contact is lost. The event was also | |||
reviewed by the Plant Operations Review Committee who concurred and | |||
approved of the actions'taken. Based on discussions with the operators | |||
and management personnel involved, and on a review of Technical Specifi - | |||
cation and Emergency Plan requirements, the inspector determined that the | |||
licensee's actions were appropriate and had no further questions regarding | |||
this event. | |||
13. Relocation of the Emergency Operations Facility (EOF) | |||
In a letter dated April 3,1985, the licensee informed Region I that they | |||
planned to begin transferring equipment from the existing EOF at the | |||
Information Center to the nearly completed permanent facility at the | |||
Fulton County Airport on May 1, 1985. During the one month interval- | |||
estimated for the transfer, Emergency Plan activation would necessitate | |||
that EOF functions be carried out from the Technical Support Center (TSC) | |||
until equipment was transferred back to the Visitor Center. A review of | |||
the Emergency Plan and the associated implementing procedures indicates | |||
that the TSC is formally tasked with carrying out the responsibilities of | |||
the EOF until that facility is fully activated and the TSC is relieved of | |||
those duties. The inspector verified that personnel had been designated | |||
to retrieve and set up the equipment if activation was necessary during | |||
the transition period. The reactor will be shut down until approximately | |||
May 15, 1985 to complete a refueling / maintenance outage. The plans for | |||
the transition to the new EOF were acceptable. The inspector had no | |||
further questions in this area. | |||
14. Review of Periodic and Special Reports | |||
Upon receipt, the inspector reviewed periodic and special reports. The | |||
review included the following: Inclusion of information required by the | |||
: NRC; test results and/or supporting information consistent with design | |||
predictions and performance specifications; planned corrective action for | |||
resolution of problems, and reportability and validity of report informa- | |||
tion. The following periodic reports were reviewed: | |||
. | |||
-- | |||
March 1985 Operating Status Report, dated April 9,1985. | |||
4 | |||
-- | |||
April 1985 Operating Status Report, dated May 7, 1985. | |||
15. Exit Interview | |||
At periodic intervals during the course of this inspection, meetings were | |||
held with senior facility management to discuss inspection scope and | |||
findings. On June 7,1985, the inspector met with licensee represen- | |||
tatives (denoted in paragraph 1) and summarized the scope and findings of | |||
the inspection as they are described in this report. | |||
. | |||
Based on his review of this report, the inspector determined that this | |||
i report does not contain information subject to 10 CFR 2.790 restrictions. | |||
! | |||
i | |||
. | |||
,- . . , | |||
__ _ | |||
. | |||
- | |||
O ^ | |||
U | |||
- | |||
U | |||
- | |||
, | |||
.- | |||
4 | |||
Attachment A | |||
Component Configurations | |||
The systems listed below were noted to contain components on - | |||
piping with design pressures equal to or less than 70% of the | |||
design pressure of the primary coolant system. | |||
' | |||
1) Interfacing system: Core Spray | |||
Piping location: In | |||
Number of. Penetrations: 2 Penetration diameter: 10 inches | |||
Component lineup: | |||
RPV-MV-AOCK-I-MOV-MOV-H/L-PRV-CK-P | |||
LO' NC NO | |||
Low Pressure (psig): 400 | |||
High Pressure (psig): 1250 | |||
2). Interfacing system: Low Pressure Coolant Injection (RHR) | |||
Piping location: In | |||
Number of penetrations: 2 Penetration diameter: 24 inches | |||
~ | |||
Component lineup: | |||
RCS-MV-AOCK-I-MOV-MOV-H/L-PRV-MOV-MV-CK-P | |||
L0 NC NO NO NO | |||
, | |||
Low Pressure (psig): 325 | |||
High Pressure (psig): 1380 | |||
3) Interfacing system: Head Spray (RHR) | |||
Piping location: In | |||
Number of penetrations: 1 Penetration diameter: 4 inches | |||
Component lineup: | |||
RPV-CK-MOV-I-MOV-H/L-PRV-CV-PRV-MOV-MV-CK-P | |||
NC NC NO LO | |||
Low Pressure (psig): 320 | |||
High Pressure (psig): 1250 | |||
4) Interfacing system: Shutdown Cooling (RHR) | |||
Piping locations: Out | |||
Number of penetrations: 1 Penetration diameter: 20 inches | |||
Component lineup: | |||
- | |||
,c, -- - - - ,, - --- - , ,,_ _ | |||
_ | |||
- . | |||
* | |||
, 0 | |||
2 | |||
RCS-MV-MOV-I-MOV-H/L-PRV-MOV-P | |||
L0 NC NC NC | |||
Low Pressure (psig): 150 | |||
High Pressure (psig): 1250 | |||
5)' Interfacing system: High Pressure Coolant Injection | |||
Piping. location: . In | |||
Number of' penetrations: 1 Penetration diameter: 14 inches | |||
Component lineup: | |||
RPV-MV-CK-I-AOCK-MOV-MOV-P-H/L | |||
N0 NC NO | |||
Low Pressure (psig): 100 | |||
High Pressure (psig): 1320 | |||
6) Interfacing system: Reactor Core Isolation Cooling | |||
Piping location: In | |||
Number of penetrations: 1 Penetration diameter: 4 inches | |||
Component lineup: | |||
RPV-MV-CK-I-AOCK-MOV-MOV-P-H/L | |||
NO NC NO | |||
Low Pressure (psig): 60 | |||
High Pressure (psig): 1320 | |||
Abbreviations on this Attachment | |||
AOCK - Air Operated Check Valve | |||
. CK - Check Valve | |||
CV - Control' Valve | |||
H/L High/ Low Pressure Interface | |||
I - ~ Containment Penetration | |||
IN - Flow Toward Reactor | |||
LO - Locked Open | |||
MOV - Motor Operated Valve | |||
MV - Manual Valve | |||
NC'- Normally' Closed | |||
NO - Normally Open | |||
OUT -~ Flow From Reactor | |||
-P - Pump | |||
PRV - Pressure Relief. Valve | |||
RCS - Reactor Coolant System | |||
RPV - Reactor Pressure Vessel | |||
_ | |||
.. | |||
O | |||
- | |||
- - | |||
. | |||
. O | |||
Attachment B | |||
Procedures Reviewed | |||
The following procedures were. reviewed as part of the evaluation of the | |||
licensee's surveillance and maintenance' activities on those valves which | |||
isolate primary coolant from low pressure ECCS piping and components. | |||
1) Maintenance Procedures | |||
-- | |||
MP-59.3, Limitorque Motor Operators - SMB Model, Revision 3, | |||
dated November 7, 1984. | |||
-- | |||
MP-59.4, Maintenance Procedure for Pneumatic Valve Operators, | |||
Revision 1, dated January 10,'1985. | |||
-- | |||
.MP-59.10, Maintenance Procedure for Non-Pressure Seal Style | |||
Gate Valves, Revision 1, dated January 16, 1985. | |||
-- | |||
MP-59.12, Maintenance Procedure for Non-Pressure Style Swing & | |||
Piston Check Valves, Revision 0, dated August 29, 1984. | |||
2)' Surveillance Procedures | |||
-- | |||
F-ST-2C, RHR MOV Valve Operability' Test, Revision 13, dated | |||
November 7, 1984. | |||
-- | |||
F-ST-2F, LPCI and LPCI MOV Power Supply Simulated Automatic | |||
Actuation Test and LPCI Battery Service Test, Revision 15,' dated | |||
April 10, 1985. | |||
-- | |||
F-ST-2G, RHR Isolation Valve Control Logic System Functional | |||
Test, Revision 13, dated April 17, 1985. | |||
-- | |||
F-ST-2H, LPCI Subsystem Logic System Functional Test, Revision | |||
12, dated April 17, 1985. | |||
-- | |||
F-ST-2P, RHR Shutdown Cooling and Head Spray Simulated | |||
Automatic Isolation Test, Revision 8, dated April 10, 1985. | |||
-- | |||
F-ST-2S, Valve Testing - Residual Heat Removal, Revision 7, | |||
dated December 14, 1983. | |||
-- | |||
F-ST-3A, Core Spray / Flow Rate / Valve Operability Test, Revision | |||
17, dated December 19, 1984. | |||
-- | |||
F-ST-38, Core Spray Simulated Automatic Actuation Test, | |||
Revision 8, dated April 10, 1985. | |||
. | |||
. | |||
O | |||
- | |||
- - | |||
. | |||
.. O | |||
. 2 | |||
-- | |||
F-ST-3J, Core Spray Subsystem Logic Functional Test, Revision | |||
12, dated April 17, 1985. | |||
-- | |||
F-ST-3M, Valve Testing - Core Spray System - Cold Shutdown | |||
Only,-Revision 3, dated May 19, 1982. | |||
-- | |||
F-ST-4A, HPCI Simulated Automatic Actuation Test, Revision 12, | |||
dated April 10, 1985. | |||
-- | |||
F-ST-48, HPCI Flow Rate /HPCI Pump Operability /HPCI Valve | |||
Operability Tests, Revision 19, dated January 3, 1985. | |||
-- | |||
F-ST-4E, HPCI Subsystem Logic System Functional Test, Revision | |||
19, dated April 10, 1985. | |||
-- | |||
F-ST-4H, RCIC/HPCI Valve Testing, Revision 8, dated August 17, | |||
1984. | |||
-- | |||
F-ST-24, ISI RCIC Valve Testing, Revision 6, dated April 18, | |||
1984. | |||
-- | |||
F-ST-24A, RICI Pump and Valve Operability / Flow Rate Test, | |||
Revision 17, dated January 3, 1985. | |||
-- | |||
F-ST-24E, RCIC Simulated Automatic Actuation Test, Revision 9, | |||
dated April 10, 1985. | |||
-- | |||
F-ST-398, Type "B" & "C" LLRT of Containment Penetrations, | |||
Revision 14, dated March 20, 1985. | |||
-- | |||
F-ST-39J, Leak Testing of RHR and Core Spray Testable Check | |||
Valves ~, Revision 0, dated May 18, 1983. | |||
3) Miscellaneous Procedures . | |||
-- | |||
TOP-72, Verification of Disk Position for CS and RHR Testable | |||
Check Valves, Revision 0, dated May 24, 1985. | |||
-- | |||
WACP 10.1.1, Procedure for Control of Maintenance, Revision 9, | |||
dated September 28, 1984. | |||
i | |||
O O | |||
- | |||
.- . | |||
. | |||
. | |||
. | |||
NRC Form 6 Rev. Oct. 80 | |||
Transaction Type | |||
New Item OUTSTANDING ITEMS FILE | |||
_x_ Modi fy SINGLE DOCKET ENTRY FORM | |||
Delete | |||
Docket Number Doerflein Linville | |||
50-333 | |||
Originator Reviewing Supervisor | |||
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C | |||
77-26-06 85-09-0 85-05-31 | |||
Originator Modifier / Closer | |||
'Doerflein | |||
Description: | |||
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C | |||
83-04-03 85-09-0 85-05-31 | |||
Originator Modifier / Closer | |||
Doerflein | |||
Description: | |||
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C | |||
--- | |||
Originator Modifier / Closer | |||
Description: | |||
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C | |||
- - | |||
Originator Modifier / Closer | |||
Descript. ion: | |||
IR FITZ 85-09 - 0029.0.0 | |||
06/19/85 | |||
}} |
Revision as of 12:16, 4 September 2020
ML20129B291 | |
Person / Time | |
---|---|
Site: | FitzPatrick |
Issue date: | 06/28/1985 |
From: | Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
To: | |
Shared Package | |
ML20129B279 | List: |
References | |
50-333-85-09, 50-333-85-9, NUDOCS 8507150483 | |
Download: ML20129B291 (21) | |
See also: IR 05000401/2005031
Text
,
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.
.
. O O
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
DCS Numbers
50-333-850322
50-333-850418
50-333-850421
50-333-850503
50-333-850220
50-333-850506
Report No. 85-09
Docket No. 50-333
License No. OPR-59 Priority --
Category C
Licensee: Power Authority of the State of New York
P.O. Box 41
Lycoming, New York 13093
Facility Name: J.A. FitzPatrick Nuclear Power Plant
Inspection At: Scriba, New York
Inspection Conducted: April 1, - May 31, 1985
Inspectors:
L.T. Doerflein, Senior Resident Inspector
W.J. Lazarus, Senior Emergency
Preparedness Specialist
A.J. Luptak, Resident Inspector, NMP-1
Approved by:
J
' 44)p, be 'y//
C. Linv1 TTe', Chief,/%f actor
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rojects Section 2C V
' Inspection Summary:
Inspection on April 1, - May 31, 1985
(Report No. 50-333/85-09)
Areas Inspected: Routine and reactive inspection during day and backshift hours
by two resident inspectors and one region based inspector (200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />) of
licensee action on previous inspection findings, licensee' event report review,
operational safety verification, survelliance observations, maintenance
observations, plant startup from refueling, determination of reactor shutdown
- margin, startup testing of the Analog Transmitter Trip System, followup on
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licensee response to GE Service Information Letter No. 402, review of the
Emergency Core Cooling Systems subject to potential overpressurization, follow-
up on licensee event, relocation of the Emergency Operations Facility and
review of periodic and special reports.
Results: No violations were identified in the areas inspected.
However, as discussed in paragraph 10, we are concerned about the failure to
implement a modification on the Containment Atmosphere Dilution System to
protect the carbon steel nitrogen makeup lines from low temperature brittle
fracture. The significance of this modification was highlighted by the
failure of the vent header.at another facility, during the past year, due to
improper operation of the nitrogen inerting system. We are also concerned
that this maybe indicative of a general lack of progress in reducing the
modification backlog identified in inspection report 50-333/82-24.
The continuing problems with pilot valve seat leakage and setpoint drift of
the target Rock safety relief valves (discussed in paragraph 3) renew concerns
regarding the need for increased management attention in pursuing resolution
of these problems.
Other concerns involving Source Range Monitor and Intermediate Range Monitor
instrument dry tube cracking, the Shutdown Margin demonstration, and the
inadvertent lifting of a fuel bundle from the reactor core are documented in
paragraphs 6., 8., and 12. respectively.
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DETAILS
1. Persons Contacted
- R. Baker, Technical Services Superintendent
V. Childs, Senior Licensing Engineer
- R. Converse, Superintendent of Power
M. Curling, Training Superintendent
- W. Fernandez, Operations Superintendent
- H. Glovier, Resident Manager
H. Keith, Instrument and Control Superintendent
D. Lindsey, Assistant Operations Superintendent
R. Liseno, Maintenance Superintendent
- E. Mulcahey, Radiological & Environmental
Services Superintendent
R. Patch, Quality Assurance Superintendent
T. Teifke, Security & Safety Superintendent
The inspector also interviewed other licensee personnel during this
inspection including shift supervisors, administrative, operations, health
physics, security, instrument and control, maintenance and contractor
personnel.
- Denotes those present at the exit interview.
2. Licensee Action on Previous Inspection Findings
(0 pen) Unresolved Item (333/77-26-06): In a letter dated November 14,
1977, the architect-engineer indicated that the Containment Atmosphere
Dilution System logic would be modified to provide low temperature pro-
tection for the carbon steel nitrogen makeup lines. The inspector noted
that this modification has not been implemented. Additional details on
this item are discussed in paragraph 10. of this report.
(0 pen) Inspector Followup Item (333/83-04-03): The inspector noted that
the licensee continues to have problems with setpoint drift on the two
stage Target Rock safety relief valves. Additional details on this item
are discussed in paragraph 3. of this report.
3. LicenseeEventReport(LER) Review
The inspector reviewed LER's to verify that the details of the events were
clearly reported. The inspector determined that reporting requirements
had been met, the report was adequate to assess the event, the cause
appeared accurate and was supported by details, corrective actions
appeared appropriate to correct the cause, the form was complete and
generic applicability to other plants was not in question.
LER's 85-09*, 85-10*, 85-11, 85-12, 85-13* were
,
reviewed.
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- LER's selected for onsite followup.
LER's 85-09 and 85-13 reported that, when tested, a total of five Target
Rock two stage safety relief valves had setpoints outside the Technical
Specification allowable tolerance. The vendor believes that the possible
causes of this setpoint drift are inadequate clearances in the laberinth
seal area and pilot valve seat leakage. The vendor is paying particular
attention to laberinth seal clearance during valve overhaul. The licensee
was also informed by the vendor that the pilot seat leakage could be
caused by testing the valves at to low a steam pressure such that the
pilot valve doesn't have any cushion effect when shutting. As a result,
the licensee revised the surveillance procedure to increase the test
pressure to 250-300 psig. However, despite this change, following safety
relief valve testing during the startup from the 1985 refueling outage,
the licensee noted indications of pilot seat leakage on the "F" safety
relief valve. The inspector will continue to review licensee's progress
in resolving the safety relief valve drift during a subsequent inspection.
LER 85-10 reported that a fuel bundle was inadvertently lifted from the
reactor core when it was caught on one of the lock levers of the fuel
support grapple. Details of this event are discussed in paragraph 12. of
this report.
4. Operational Safety Verification
a. Control Room Observations
Daily, the inspectors verified selected plant parameters and equip-
ment availability to ensure compliance with limiting conditions for
operation of the_ plant Technical Specifications. Selected lit
annunciators were discussed with control room operators to verify
that the reasons for them were understood and corrective action, if
required,' was being taken. The inspectors observed shift turnovers
biweekly to ensure proper control room and shift manning. The
inspectors directly observed the operations, listed below to ensure
adherence to approved procedures:
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Reactor startup on May 28, 1985.
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Issuance of RWP's and Work Request / Event / Deficiency forms.
No violations'were identified,
b. Shift loos ~ and Operating Records
Se'locted shif t logs and operating records were reviewed to obtain
information on plant problems and operations, detect changes and
trends in performance, detect possible conflicts with Technical
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Specifications or regulatory requirements, determine that records are
being maintained an'd reviewed as required, and assess the effective-
ness of the communications provided by the logs.
No violations-were identified,
c . Plant Tours
During the inspection period, the inspectors made observations and
conducted tours of the plant. During the plant tours, the inspectors
conducted a visual inspection of selected piping between containment
and the isolation valves for leakage or leakage paths. This included
verification that manual valves were shut, capped and locked when
required and that motor operated valves were not mechanically
blocked. The inspectors also checked fire protection, house-
keeping / cleanliness, radiation protection, and physical security
conditions to ensure compliance with plant procedures and regulatory
requirements.
No violations were identified.
d. Tagout Verification
The inspector verified that the following safety-related
protective tagout records (PTR's) were proper by
observing the positions of breakers, switches and/or valves.
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PTR 850548 on "C" Residual Heat Retraval Service Water System.
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PTR 850572 on "B" Station Battery Charger.
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PTR 850603 on the Reactor Protection System.
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PTR-850647 on the "A" Emergency Service Water System.
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PTR 850783 on the "B" Residual Heat Removal System.
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PTR 850858 on the "B" Residual Heat Removal Service Water
System.
No violations were identified.
5. ' Surveillance Observations
The inspector observed portions of the surveillance procedures listed
below to verify that the test instrumentation was properly calibrated,
approved procedures were used, the work was performed by qualified per-
sonnel, limiting conditions for operation were met, and the system was
correctly restored following the testing:
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F-ST-398, Type "B" and "C" LLRT of Containment Penetrations,
Revision 14, dated March 20, 1985, performed April 8, 9 and 15,
1985.
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F-ST-29E, Backup Scram Valves Functional Test, Revision 0,
dated February 27, 1985, performed April 19, 1985.
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F-ST-39L, Reactor Vessel Hydrostatic Test, Revision 0, dated
May 1, 1985, performed May 7, 1985.
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F-ISP-1, Instrument Line Flow Check Valve Operability Test,
Revision 5, dated June 18, 1981, performed May 8, 1985.
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F-ST-16I, 125 VDC Station Battery Service Discharge and
Charger Performance Test, Revision 1, dated April 27, 1983,
performed May 17, 1985.
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F-ST-290, Integrated Scram System Test, Revision 2, dated
January 23, 1985, performed May 31, 1985.
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F-ST-5N, APRM Instrument Functional Test (Refuel, Startup,
Shutdown Mode), Revision 7, dated October 31, 1984, performed May
, 31, 1985.
The observations of the Local Leak Rate Testing (LLRT). included the post
maintenance LLRT on the repaired Reactor Water Cleanup inboard contain-
ment isolation valve (12-MOV-15) and the "B" Feedwater outboard contain-
ment isolation valve (34-NRV-1118). The inspector noted that 12-M0V-15
passed the LLRT while 34-NRV-111B failed and had to be reworked. The
inspector also noted that 34-NRV-111B had to be reworked several times
before successfully passing an LLRT. As discussed in paragraph 6. of this
report, the inspector witnessed a portion of the maintenance performed on
34-NRV-1118. Based on these observations and discussions with licensee
personnel, the inspector determined that the licensee adequately performed
retesting (LLRT) on repaired containment isolation valves.
No violations were identified.
6. Maintenance Observations
a. The inspector observed portions of various safety-related maintenance
activities to determine that redundant components were operable,
these activities did not violate the limiting conditions for opera-
tion, required administrative approvals and tagouts were obtained
prior to initiating the work, approved procedures were used or the
activity was within the " skills of the trade," appropriate radio-
logical controls were properly implemented, ignition / fire prevention
controls were properly implemented, and equipment was properly tested
prior to returning it to service.
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b. During this inspection period, the following activities
were observed:
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WR 00/21073 on the functional testing of safety related
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WR 07/38673 on the replacement of "D" Intermediate Range
Monitor dry tube.
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WR 34/35562 on the repair of "B" Feedwater Outboard
Containment Isol.cion Check Valve.
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WR 46/25455 on the repair of the "A" Emergency Service Water
Pump discharge check valve.
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WR 71/22674 on the replacement of "A" Low Pressure Coolant
Injection System Battery
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F-IMP-71.18B on the post maintenance testing of replaced HFA
relays.
c. During the 1985 refueling outage in-vessel Inservice Inspection (ISI)
visual examinations, the licensee identified cracks in all twelve
Source Range Monitor (SRM) and Intermediate Range Monitor (IRM)
instrument dry tubes. The cracks were all in the upper portion of
the dry tube and were similar to those observed at other BWR's and
discussed in General Electric Service Information Letter (SIL) ido.
409. The indications are believed to be the result of Irradiation
Assisted Stress Corrosion Cracking (IASCC). The inspector observed
portions of the videotape containing the dry tube examinations. The
inspector noted that the licensee individual performing the evalua-
tions was qualified as a Level III inspector.
The dry tube ISI results were also evaluated by General Electric (GE)
who concluded that the licensee could operate one additional cycle
with the existing dry tubes with no adverse impact on safety. How-
ever, GE recommended that five of the dry tubes be replaced. Based
on this recommendation, the licensee replaced the dry tubes at core
locations 12-9, 28-33, 36-9, and 36-25 (IRM H, D, G and SRM C) which
had possible indications below the bottom tube weld at the primary
pressure boundary and the dry tube at 28-25 (IRM E) which had a
noticeable bend at the crack location. The licensee also had to
replace the dry tube at 12-33 (SRM A) after the top portion broke off
when it was bumped by a double blade guide during core alterations.
The inspector noted that the licensee recovered the piece which broke
off.
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The inspector noted that the replacement dry tubes were the same
design as the original dry tubes and therefore subject to IASCC.
General Electric in'dicated that a dry tube with materials less
susceptable to IASCC would be available in the near future. The
licensee tentatively plans on replacing the remaining six cracked
dry tubes with ones of the new design during the next refueling
outage and on replacing the six dry tubes just installed during the
following outage to resolve the problem with dry tube cracking.
No violations were identified.
7. Plant Startup from Refueling
The inspectors witnessed portions of the plant startup conducted May 28-
31, 1985 to verify that: the startup was performed in accordance with
approved procedures; surveillance tests required to be performed
prior to startup were satisfactorily completed; systems were properly
aligned prior to startup; the control rod withdrawal sequence was avail-
able; and startup activities were conducted in accordance with Technical
Specification requirements.
No violations were identified.
8. Shutdown Margin Demonstration
The inspector observed the Shutdown Margin (SDM) demonstration performed
on May 6, 1985. The test utilized the diagonally adjacent rod method and
was performed in accordance with an approved procedure. The inspector.
noted that the licensee terminated the test with the margin rod (22-27) at
notch position 12 and the object rod (26-31), the analytically determined
highest reactivity worth control rod, at position 36 after Source Range
Monitor (SRM) count rate went from 60 counts per second (cps) to approxi-
mately 200,000 cps during the test. The procedure required the object rod
to be fully withdrawn. Using data obtained during the test, the fuel
vendor determined the SDM to be .54% AK/K. The Technical Specifications
required that the SDM for Cycle 7 be greater than .44%_AK/K. However, due.
to the unusual increase in SRM count rate during the test and because the
calculated SDM was significantly below the SDM design value of 1.17% AK/K,
additional NRC inspections by regional specialists were conducted to
evaluate the results of the tests.
As part of his followup to the SDM test, the resident inspector reviewed
the completed core verification maps prepared by the licensee and noted
that the final verified position of the fuel bundles was in accordance
with the FitzPatrick Cycle 7 Management Report dated April 1985. The
inspector noted that the verification had been performed by a Reactor
Engineer and a licensed operator. A separate review of the videotapes was
conducted by two Quality Control (QC) inspectors. Following the SDM test,
two additional QC inspectors performed another review of the core veri-
fication videotapes. The resident inspector also viewed the core
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verification videotapes and verified, for a sample of one half the core,
that the fuel bundle position and orientation were in accordance with the
core map. The videotapes were generally clear and the serial numbers on
the fuel assemblies were adequately visible. No discrepancies were
identified.
On May 25, 1985, the licensee performed a SDM demonstration using the
in-sequence critical method to verify adequate SDM before the startup
from the refueling outage. The inspector reviewed the test results
obtained in accordance with the licensee's procedure and noted that the
calculated SDM with the strongest control rod fully withdrawn was .79%
AK/K. During the plant startup on May 28, 1985, another in-sequence
critical demonstration resulted in a calculated SDM of .81% AK/K.
Based on the data reviewed, the inspector determined that the demonstrated
SDM met the Technical Specification requirements. Based on a review of
correspondence with the fuel vendor and on di!cussions with licensee
personnel, the inspector noted that the deviations between the calculated
SDM and the design values are probably due to calculational uncertainties.
Additional details on the evaluation of the SDM demonstrations are docu-
mented in inspection reports no. 50-333/85-14 and 50-333/85-17.
9. Startup Testing-Analog Transmitter Trip System
The inspector reviewed portions of preoperational procedure no. Misc. 02A,
"Preoperational Test of Analog Transmitter / Trip System for RPS and ECCS
Sensor Trip Inputs (Mod. No. F1-82-53)", Revision 1, dated April 24, 1985,
to verify that the procedure was properly approved and included: procedure
scope and objectives; prerequisities; precautions; acceptance criteria;
checkoff lists; reference to drawings and applicable procedures; pro-
visions for recording details of the conduct of the test; provision for
identification of personnel conducting the testing and evaluation of test
data; and provision for quality control verification of critical' steps.
The inspector also verified that changes to the preoperational procedure
were reviewed as required by Technical Specifications.
The inspector also witnessed portions of the testing and verified that the
test was conducted in accordance with the approved procedure and that
quality control verification was performed during the test. For the
testing observed, the inspector noted that the test results were within
the previously established acceptance criteria.
No violations were identified.
10. Followup on licensee response to General Electric Service
Information Letter (SIL) No.402, Wetwell/Drywell Inerting
, Based on discussions with licensee personnel and a review of Operating
Experience Report No. 185, the inspector verified that the licensee eval-
uated the design and operation of the liquid nitrogen based inerting
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system as recommended by General Electric SIL No. 402. The evaluation was
performed by the Performance and Reliability Department in accordance with
procedure PS0 28, " Operating Experience Feedback," and identified problems
with the operation and testing of the liquid nitrogen inerting system.
The inspector reviewed procedures F-0P-37, " Nitrogen Ventilation and
Purge; Containment Atmosphere Dilution (CAD); Containment Vacuum
Relief and Containment Differential Pressure Systems," Revision 20, and
F-ST-25A, " Nitrogen System Low Temperature Simulated Automatic Isolation
Functional Test," Revision 0, and determined that, in response to these
findings, the licensee revised or developed procedures to verify proper
operation of the nitrogen inerting system automatic isolation prior to
inerting the containment and to add cautions on system monitoring if the
automatic isolation . valves are bypassed, such as during containment
inerting directly from a nitrogen truck. The inspector also reviewed
calibration data sheets dated October 2,1984 to verify that the tempera-
ture sensors used for nitrogen system monitoring and for the automatic
isolation functions were properly calibrated. The inspector verified that
these sensors have been added on the calibration schedule to ensure
periodic recalibration.
The inspector also noted that, during the evaluation, the licensee
reviewed the portions of the liquid nitrogen system used for containment
makeup during normal operations. This review noted that a modification
was proposed by the architect-engineer in a letter dated November 14,
1977, to resolve a deficiency identified in Inspection Report No.
50-333/77-26 concerning the lack of low temperature isolation protection
for the carbon steel nitrogen makeup lines in case of a loss of the elec-
tric heater downstream of the ambient vaporizers._ Based on discussions
with licensee personnel, the inspector found that this modification had
not been implemented. The inspector expressed concern that no action had
.been taken on this problem for so long. The' licensee acknowledged the
inspector's concern and stated that after the refueling outage emphasis
would be placed on identifying and completing these old moficiations. The
inspector will review licensee progress in this area during future
inspections.
The inspector reviewed the completed data sheets for procedure F-ST-39E,
"Drywell to Suppression Chamber Vacuum Breaker Leak Test," performed on
February 15, 1985. The purpose of this procedure is to determine the
total equivalent bypass area leakag'e (normally expected through the vacuum
breakers) between the Drywell and Suppression Pool. The test consists of
maintaining a specified differential pressure (1.0 psid) between the
Drywell and Suppression Pool and monitoring the rise in Suppression Pool
pressure over a ten minute period. The inspector noted that the results
of.the test were satisfactory and there were no indications of bypass
leakage. As discussed in paragraph 6. of Inspection Report No. 50-333/-
84-18, the inspector has previously determined that the licensee reviewed
plant data and concluded that there were no anomalies which could be
indicative of Suppression Pool vent header cracks. The inspector had also
previously reviewed Quality Control Inspection Report No. F84-057, which
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documented the visual inspections performed on portions of the vent
header, both inside and outside, including the nitrogen penetration to
suppression pool shell weldment. No cracks were.found during these visual
inspections. The inspector noted that no ultrasonic testing of the
nitrogen penetration was performed due to lack of baseline data.
Based on his review, the inspector concluded that the licensee implemented
the recommendations of SIL No. 402 regarding vent header cracking. As
noted above, the inspector's only concern was the licensee's failure to
implement the modification needed to provide low. temperature isolation
protection for the nitrogen makeup lines.
11. Review of Emergency Core Cooling Systems Subject
to Potential Overpressurization
The inspectors reviewed records and procedures and held discussions with
licensee personnel to evaluate the design features and administrative
controls that are used to minimize the potential for Emergency Core
Cociing System (ECCS) overpressurization.
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a. Verification of as-built isolation interfaces
The inspectors reviewed various drawings and Stone and Webster Line
Designation Tables to identify those systems which contain components
or piping with design pressures equal to or less than 70% of the
design pressure of the primary coolant system. The inspectors noted
that the High Pressure Coolant Injection (HPCI), Reactor Core Isola-
tion Cooling (RCIC), Residual Heat Removal (including the Low
Pressure Coolant Injection (LPCI) and Shutdown Cooling / Head Spray
Modes), and Core Spray (CS) Systems all contain such high/ low
pressure interfaces. Additional details on the component configur-
ation and the design high and low pressures can be found in attach-
ment A to this report.
The inspectors also.noted that, with respect to these systems, LPCI,
l CS, HPCI and RCIC all have testable check valves (valves 10-A0V-68A
i and B, 14-A0V-13 A and B, 23-A0V-18, and 13-A0V-22 respectively).
!
The air operators on these valves are maintained operable and are
used only during cold shutdown to verify operability of the check
valve as required by Technical Specifications.
The inspectors determined that for each of the systems with a test-
able check valve, the air operated check valve (A0V) and the first
motor operated valve (MOV) (a normally closed valve) upstream of the
A0V provide isolation for the high and low pressure interface. The
second MOV (a normally open valve) upstream of the A0V can also be
i used to provide the isolation function. For Head Spray, the isola-
i tion function is provided by a check valve and the normally closed
l inboard and outboard containment isolation MOV's. For Shutdown
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C:oling, the isolation function is provided by the normally closed
l inboard and outboard containment isolation MOV's.
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The inspectors focused their review of surveillance and maintenance
activities on the " isolation valves" identified above which normally
maintain isolation for each high/ low pressure interface as well as
those valves which could be used to provide the isolation function.
b. Surveillance Activities
The inspectors reviewed the various surveillance test procedures
listed in attachment B and held discussions with licensee
personnel to determine the surveillance activities that apply to
the isolation valves at each high/ low pressure interface. The-
inspectors noted that there are several surveillance tests which
are conducted to test the operation of the isolation valves for
each ECCS system and RCIC. The inspector also noted that,
although there is considerable overlap with ASME Section XI, the
frequency of the tests are usually determined by the Technical
Specifications which are more restrictive. The following is a
summary of the surveillance testing performed on the isolation
valves:
1. A valve operability test is performed once a month to verify
the valves operate correctly when cycled from the control room.
When performing this test on CS or RHR the plant may be at power
or shutdown. For HPCI and RCIC'the plant must be at power with
steam available.
2. A system automatic actuation test is performed once a cycle
by inputing simulated signals and ensuring the systems respond as
appropriate. When performing this test on CS or RHR the plant
must be shutdown and depressurized as the isolation valves are
operated. For HPCI and RCIC the test is performed at power with
the pump discharge lined up to the Condensate Storage Tank and
with the inboard isolation shut and power removed.
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3. A system logic functional test is performed every six months
by inputing simulated signals and assuring that the system logic
functions properly. The plant may be operating or shutdown when
testing CS or RHR. The plant is at power when testing HPCI and
RCIC. During this test the inboard isolation valve (for each
system) is shut with the power removed.
4. Local Leak Rate Testing is performed on all isolation valves
(except for the HPCI and RCIC testable check valve and outboard
isolation valve) each refueling outage.
5. The CS, RHR, HPCI and RCIC testable check valves are cycled
j each cold shutdown greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> if not done within the
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The inspectors noted that the preceutions associated with the sur-
veillance tests are.not uniform. Several of the tests contain
precautions concerning opening both isolation valves simultaneously
while a few others caution to ensure steps are followed in proper
sequence. Some of the tests contain no precautions concerning the
isolation valves. The inspectors also noted that the precautions
appear to be concerned with the possibility of injecting water into
the reactor vessel rather than.the potential for ECCS overpressuri-
zation. However, the inspectors determined that the sequence of the
test procedures (consisting of concise, specific, and identifiable
steps each of which requires a verification signature on the data
sheet) minimizes the potential for ECCS overpressurization.
The inspectors also noted that, in some of the tests, the
interlock between the isolation valves for the low pressure ECCS
systems is bypassed when simulated pressure signals are inputed.
Inadvertent valve operation is presented during these tests by
removing power to the valve operators. The inspectors determined
that, if a jumper is installed or an interlock bypassed, the
procedure ensures that the system is returned to normal at the
completion of testing.
The inspectors noted that the training for operators, with respect to
the isolation valves, has basically consisted of. placing industry
information on valve problems (IE Information Notices, INPO SOER's
etc.) in the required reading book. There is no specific training on
the surveillance testing of these violation valves.
c. Maintenance Activities-
The inspectors reviewed maintenance procedures, work requests and
Licensee Events Reports to determine the maintenance activities and
practices that apply to the isolation valves and their operators.
Based on this review and discussions with licensee personnel, the
inspectors noted that, in general, the licensee has not performed
preventive maintenance on the isolation valves. However, the
licensee indicated that a preventive maintenance program for all
safety related motor operated valves (M0V's) would be implemented in
the near future. This program would include items such as changing
grease and checking torque switch settings on a periodic basis. With
the exception of a few failures of valve motors and air operated
solenoid valves, the inspectors noted that the majority of corrective
maintenance on the isolation valves was due to Local Leak Rate Test
failures, body to bonnet and packing leaks, problems with torque
switch settings, and position indication failures. The frequency of
the maintenance varied for the isolation valve involved.
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Some valves required very little maintenance while others, such as
the RHR, CS and RCIC testable check valves and both shutdown cooling
isolation valves, required considerable maintenance.
Only one modification (other than environmental qualification
. upgrading) has been completed on these isolation valves. This modi-
fication was. initiated to resolve recurring maintenance problems on
the inboard Shutdown Cooling (SDC) isolation valve and involved
rerouting the SDC line (to provide easy access to the valve for
-maintenance) and installing a new valve. Another recurring problem
has been the failure of the disc position indication on the RHR and
CS testable. check valves (3 out of 4 are currently inoperable). The
licensee has decided not to maintain these indicators operable due to
the frequency of failures and ALARA considerations. As a result the
licensee uses actuator arm and valve stem movement to verify opera-
tion during required surve.illance testing. The licensee has also
recently implemented procedure TOP-72, " Verification of Disk Position
for. CS and RHR Testable Check Valves," to verify these valves
(without position indication) are shut following t,esting by
monitoring the pressure lag across the valve during a reactor
startup.
The inspectors reviewed the maintenance procedures, (listed in
attachment B) used on the isolation valves and determined that
they were adequate. The inspectors noted that there are separate
procedures for maintenance on motor operators, pneumatic valve
operators, check valves, and gate valves. Each procedure contains
Quality Control inspection hold points including in the area of post
maintenance testing. In general, the post maintenance testing
section of each procedure requires cycling the valve several times to
verify proper. actuator and/or valve operation. Following valve main-
tenance, the licensee's Work Activity Control Procedures raquire the
operations department to perform any additional testing to verify the
valve meets the Technical Specification requirements (stroke time,
leak rate, etc.) before declaring the valve operable.
Although not related to the industry problems with the isolation
valves, the inspectors noted that maintenance personnel (Electricians
and Mechanics) have received training on valve maintenance from valve
vendors within the last two years. The inspectors noted that the
amount of corrective maintenance on all safety related valves appears
to be declining and the licensee attributes part of it to this
training.
d. Conclusion
The inspectors noted that the licenree has one design feature which
would provide early indication of an ECCS overpressurization.
Specifically, the Core Spray System is annunciated and provides an
alarm (Core Spray System A (B) High Pressure Valve Leakage) if the
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pressure upstream of the inboard injection valve increases to 450
psig, indicating leakage by the inboard and testable check valves.
In addition, the inspectors noted that, in response to industry
operating experience regarding previous isolation valve problems, the
licensee now has the auxiliary operator monitor and log (shiftly)
HPCI and RCIC casing temperatures which would increase if there was
backleakage through the isolation valves. The auxiliary operators
are also required to tour (at least once per shift) the areas con-
taining the ECCS and RCIC systems to identify and log any abnormal-
ities some of which, such as CS and RHR system relief valve lifting
or excessive pump seal leakage, may be indicative of a backleakage
problem.
Based on the records reviewed and discussions with licensee per-
sonnel, the inspectors determined that there does not appear to have
been any instances of actual overpressurization of the low pressure
ECCS piping or components. The inspectors also determined that the
maintenance and surveillance procedures reviewed appear adequate to
minimize the potential for such an event.
12. Followup on a 1.icensee Event
On April 21, 1985, while preparing to remove a fuel support piece to allow.
uncoupling control rod 10-35 from the refuel floor, the licensee inadver-
tently lifted a fuel bundle (at location 7-36) out of the reactor core.
The operators had just lowered the fuel support grapple, which was
attached to the frame mounted hoist, to the upper grid. When they-
operated the engage button to allow the grapple to pass.through the upper
grid, an air leak developed which obscured the operators' vision. The
grapple was raised to determine the source of the air leak. As it was
being raised the air leak stopped after the operator cycled the engage and
disengage buttons. When vision was restored, the operators noted that a
fuel bundle had been caught on one of the grapple lock levers and had been
lifted completely out of the core. The operators immediately stopped
grapple motion and informed the control room. The inspector noted that,
prior to and during this event, the licensee had the Standby Gas Treatment
System operating and the reactor building ventilation isolated. During
the event the licensee also evacuated unnecessary personnel from the
Reactor Building. Additional supervisory and management personnel
reported to the refuel floor.
The licensee secured the fuel bundle to the refuel bridge using a "J" hook
and rope. The fuel bundle was then raised using the frame mounted hoist-
and transferred to the Spent Fuel Pool. The inspector noted that the
bundle always remained underwater and that there was no change in the
refuel floor radiation readings monitored during the event. When the
bundle was lowered into a rack in the Spent Fuel Pool, it. slipped off the
grapple lock lever and had to be-manually lowered using the "J" hook and
rope. The fuel bundle was subsequently inspected by the licensee and
General Electric personnel and found undamaged. The licensee counseled
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all operators on this event and cautioned them to immediately stop all
in-vessel operations when visual contact is lost. The event was also
reviewed by the Plant Operations Review Committee who concurred and
approved of the actions'taken. Based on discussions with the operators
and management personnel involved, and on a review of Technical Specifi -
cation and Emergency Plan requirements, the inspector determined that the
licensee's actions were appropriate and had no further questions regarding
this event.
13. Relocation of the Emergency Operations Facility (EOF)
In a letter dated April 3,1985, the licensee informed Region I that they
planned to begin transferring equipment from the existing EOF at the
Information Center to the nearly completed permanent facility at the
Fulton County Airport on May 1, 1985. During the one month interval-
estimated for the transfer, Emergency Plan activation would necessitate
that EOF functions be carried out from the Technical Support Center (TSC)
until equipment was transferred back to the Visitor Center. A review of
the Emergency Plan and the associated implementing procedures indicates
that the TSC is formally tasked with carrying out the responsibilities of
the EOF until that facility is fully activated and the TSC is relieved of
those duties. The inspector verified that personnel had been designated
to retrieve and set up the equipment if activation was necessary during
the transition period. The reactor will be shut down until approximately
May 15, 1985 to complete a refueling / maintenance outage. The plans for
the transition to the new EOF were acceptable. The inspector had no
further questions in this area.
14. Review of Periodic and Special Reports
Upon receipt, the inspector reviewed periodic and special reports. The
review included the following: Inclusion of information required by the
- NRC; test results and/or supporting information consistent with design
predictions and performance specifications; planned corrective action for
resolution of problems, and reportability and validity of report informa-
tion. The following periodic reports were reviewed:
.
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March 1985 Operating Status Report, dated April 9,1985.
4
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April 1985 Operating Status Report, dated May 7, 1985.
15. Exit Interview
At periodic intervals during the course of this inspection, meetings were
held with senior facility management to discuss inspection scope and
findings. On June 7,1985, the inspector met with licensee represen-
tatives (denoted in paragraph 1) and summarized the scope and findings of
the inspection as they are described in this report.
.
Based on his review of this report, the inspector determined that this
i report does not contain information subject to 10 CFR 2.790 restrictions.
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Attachment A
Component Configurations
The systems listed below were noted to contain components on -
piping with design pressures equal to or less than 70% of the
design pressure of the primary coolant system.
'
1) Interfacing system: Core Spray
Piping location: In
Number of. Penetrations: 2 Penetration diameter: 10 inches
Component lineup:
RPV-MV-AOCK-I-MOV-MOV-H/L-PRV-CK-P
LO' NC NO
Low Pressure (psig): 400
High Pressure (psig): 1250
2). Interfacing system: Low Pressure Coolant Injection (RHR)
Piping location: In
Number of penetrations: 2 Penetration diameter: 24 inches
~
Component lineup:
RCS-MV-AOCK-I-MOV-MOV-H/L-PRV-MOV-MV-CK-P
L0 NC NO NO NO
,
Low Pressure (psig): 325
High Pressure (psig): 1380
3) Interfacing system: Head Spray (RHR)
Piping location: In
Number of penetrations: 1 Penetration diameter: 4 inches
Component lineup:
RPV-CK-MOV-I-MOV-H/L-PRV-CV-PRV-MOV-MV-CK-P
NC NC NO LO
Low Pressure (psig): 320
High Pressure (psig): 1250
4) Interfacing system: Shutdown Cooling (RHR)
Piping locations: Out
Number of penetrations: 1 Penetration diameter: 20 inches
Component lineup:
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2
RCS-MV-MOV-I-MOV-H/L-PRV-MOV-P
L0 NC NC NC
Low Pressure (psig): 150
High Pressure (psig): 1250
5)' Interfacing system: High Pressure Coolant Injection
Piping. location: . In
Number of' penetrations: 1 Penetration diameter: 14 inches
Component lineup:
RPV-MV-CK-I-AOCK-MOV-MOV-P-H/L
N0 NC NO
Low Pressure (psig): 100
High Pressure (psig): 1320
6) Interfacing system: Reactor Core Isolation Cooling
Piping location: In
Number of penetrations: 1 Penetration diameter: 4 inches
Component lineup:
RPV-MV-CK-I-AOCK-MOV-MOV-P-H/L
NO NC NO
Low Pressure (psig): 60
High Pressure (psig): 1320
Abbreviations on this Attachment
AOCK - Air Operated Check Valve
. CK - Check Valve
CV - Control' Valve
H/L High/ Low Pressure Interface
I - ~ Containment Penetration
IN - Flow Toward Reactor
LO - Locked Open
MOV - Motor Operated Valve
MV - Manual Valve
NC'- Normally' Closed
NO - Normally Open
OUT -~ Flow From Reactor
-P - Pump
PRV - Pressure Relief. Valve
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Attachment B
Procedures Reviewed
The following procedures were. reviewed as part of the evaluation of the
licensee's surveillance and maintenance' activities on those valves which
isolate primary coolant from low pressure ECCS piping and components.
1) Maintenance Procedures
--
MP-59.3, Limitorque Motor Operators - SMB Model, Revision 3,
dated November 7, 1984.
--
MP-59.4, Maintenance Procedure for Pneumatic Valve Operators,
Revision 1, dated January 10,'1985.
--
.MP-59.10, Maintenance Procedure for Non-Pressure Seal Style
Gate Valves, Revision 1, dated January 16, 1985.
--
MP-59.12, Maintenance Procedure for Non-Pressure Style Swing &
Piston Check Valves, Revision 0, dated August 29, 1984.
2)' Surveillance Procedures
--
F-ST-2C, RHR MOV Valve Operability' Test, Revision 13, dated
November 7, 1984.
--
F-ST-2F, LPCI and LPCI MOV Power Supply Simulated Automatic
Actuation Test and LPCI Battery Service Test, Revision 15,' dated
April 10, 1985.
--
F-ST-2G, RHR Isolation Valve Control Logic System Functional
Test, Revision 13, dated April 17, 1985.
--
F-ST-2H, LPCI Subsystem Logic System Functional Test, Revision
12, dated April 17, 1985.
--
F-ST-2P, RHR Shutdown Cooling and Head Spray Simulated
Automatic Isolation Test, Revision 8, dated April 10, 1985.
--
F-ST-2S, Valve Testing - Residual Heat Removal, Revision 7,
dated December 14, 1983.
--
F-ST-3A, Core Spray / Flow Rate / Valve Operability Test, Revision
17, dated December 19, 1984.
--
F-ST-38, Core Spray Simulated Automatic Actuation Test,
Revision 8, dated April 10, 1985.
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F-ST-3J, Core Spray Subsystem Logic Functional Test, Revision
12, dated April 17, 1985.
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F-ST-3M, Valve Testing - Core Spray System - Cold Shutdown
Only,-Revision 3, dated May 19, 1982.
--
F-ST-4A, HPCI Simulated Automatic Actuation Test, Revision 12,
dated April 10, 1985.
--
F-ST-48, HPCI Flow Rate /HPCI Pump Operability /HPCI Valve
Operability Tests, Revision 19, dated January 3, 1985.
--
F-ST-4E, HPCI Subsystem Logic System Functional Test, Revision
19, dated April 10, 1985.
--
F-ST-4H, RCIC/HPCI Valve Testing, Revision 8, dated August 17,
1984.
--
F-ST-24, ISI RCIC Valve Testing, Revision 6, dated April 18,
1984.
--
F-ST-24A, RICI Pump and Valve Operability / Flow Rate Test,
Revision 17, dated January 3, 1985.
--
F-ST-24E, RCIC Simulated Automatic Actuation Test, Revision 9,
dated April 10, 1985.
--
F-ST-398, Type "B" & "C" LLRT of Containment Penetrations,
Revision 14, dated March 20, 1985.
--
F-ST-39J, Leak Testing of RHR and Core Spray Testable Check
Valves ~, Revision 0, dated May 18, 1983.
3) Miscellaneous Procedures .
--
TOP-72, Verification of Disk Position for CS and RHR Testable
Check Valves, Revision 0, dated May 24, 1985.
--
WACP 10.1.1, Procedure for Control of Maintenance, Revision 9,
dated September 28, 1984.
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NRC Form 6 Rev. Oct. 80
Transaction Type
New Item OUTSTANDING ITEMS FILE
_x_ Modi fy SINGLE DOCKET ENTRY FORM
Delete
Docket Number Doerflein Linville
50-333
Originator Reviewing Supervisor
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C
77-26-06 85-09-0 85-05-31
Originator Modifier / Closer
'Doerflein
Description:
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C
83-04-03 85-09-0 85-05-31
Originator Modifier / Closer
Doerflein
Description:
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C
---
Originator Modifier / Closer
Description:
Item Number Type Module # Area Resp. Action Due Date Updt/Close Date 0/M/C
- -
Originator Modifier / Closer
Descript. ion:
IR FITZ 85-09 - 0029.0.0
06/19/85