IR 05000338/1989003
| ML20245C508 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 04/12/1989 |
| From: | Caldwell J, Fredrickson P, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20245C414 | List: |
| References | |
| 50-338-89-03, 50-338-89-3, 50-339-89-03, 50-339-89-3, GL-88-17, NUDOCS 8904270183 | |
| Download: ML20245C508 (45) | |
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UNITED STATES
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[p nogb~',Ao NUCLEAR REGULATORY COMMISSION
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" o 101 MARIETTA STREET. E'- if' - ATLANTA. GEORGIA 30323
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Report Nos.: 50-338/89-03 and 50-339/89-03 Licensee: Virginia Electric & Power Company Richmond, VA 23261 Docket Nos.: 50-338 and 50-339 License Nos. : NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: February 3, 1989 through March 20, 1989 Inspectors: -/b,3 i , .[ > /r , 4h2/ N J. L. Caldwell, SRI / Ddte ' Signed
'/ ) h , w h, e///2/ f f L. P. King, RI p/ Date Signed Other Inspectors: C. H. Bassett T. A. Cooper L. L. Lawyer L. S. Mellen S.'M. Shaeffer Approved by: . -
P. E. Fre'drickson, Section Chief ~
4// L/ M Oat e ' Signed Division of Reactor Projects SUMMARY Scope: This routine inspection by the resident inspectors involved the following areas: plant status, maintenance, surveillance, ESF -
walkdown, operational safety verif_ication, operating reactor events, special review of S/G tube leak, licensee event report followup, licensee action on previous inspection findings, station drawing review, preparation for refueling, and cold weather preparatio During the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshif t operations on the following days: February 6, 9, 10, 12, 13,.14, 15, 16, 17, 19, 20, 23, 25, 26, and 28, 1989; and March 1, 2, 6, 7, 12, and 14, 198 Results: The inspectors continue to be concerned about the drawing update program and the accuracy of drawing With respect to the S/G tube leak event, operator actions appeared to be responsive and prompt, based on the information on hand; but an interface problem does exist between the applicable AP and EP. The erratic operation of the CAE radiation monitor delayed the response to the tube leak and could 8904270183 890418 PDR ADOCK 05000338 G PNU L _ _- -___ - _
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j have. resulted in more significant problems, . had the etaff 'not .
responded promptl T' is ' problem ~ reveals a weakness in the carrec-
tive action' process from the similar erratic behavior during the S/G tube rupture of 198 t
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Within the areas inspected, two violations were identified f or failure to follow procedures and failure to take adequate corrective-action, and one unresolved item was. identifie Violation, Failure to follow operating procedure 1-OP-49.1A requiring
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valve 2-SW-242 to.be in the closed position (paragraph 5)'.
Violation,. Failure to take adequate corrective action to determine l the root cause for the . failure of the condenser air ejector radiation monitor due to moisture (paragraph 8.d)
- Unresolved Item, NRC review of TS 4.6.1.1.a (paragraph 5),
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" Unresolved items are matters about which more information is required to determine whether they are acceptable, or may involve violations or deviation _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _
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REPORT DETAILS Persons Contacted Licensee Employees
- Bowling, Assistant Station Manager J. Downs, Superintendent, Administrative Services
- R. Driscoll, Quality Control Manager
- R. Enfinger, Assistant Station Manager G. Gordon, Electrical Supervisor L. Hartz, Instrument Supervisor D. Heacock, Superintendent, Technical Services
- G. Kane, Station Manager
- B. Matthews, Superintendent, Maintenance T. Porter, Superintendent, Engineering
- J. Stall, Superintendent, Operations
- A. Stafford, Superintendent, Health Physics F. Termine11a, Quality Assurance Supervisor D. Thomas, Mechanical Maintenance Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personne * Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap NRC Management Site Visit: On February 21, 1989, the recently assigned Section Chief, Division of Reactor Projects, conducted a tour of the station and met with the licensee to discuss items of mutual interes . Plant Statu The inspection period began with Unit 1 operating at 88% power, day 176 of continuous operation, and coastir.g down to the refueling outage scheduled for mid-April 198 On February 16, Unit i developed an identified primary leak rate greater than 10 gpm. The leak was reduced to less than 10 gpm by isolating letdown but increased to greater thar, the TS limit of 10 gpm again on February 17. This time the licensee was not able to reduce the leak cate within the required four hours and an Unusual Event was declared. The leak was discovered to be a packing leak on a loop B RTD bypass isolation valve and was secured by back-seating the valve (see paragraph 7). The Unusual Event was terminated and the unit continued to operate until February 25 when a reactor trip occurred. Just following the reactor trip, the licensee experienced a failure of a plug on the hot leg side of the IC S/ This failed plug punched a hole in tube row 3
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column 60 and resulted in a primary to secondary leak of approximately 70 gpm. The licensee declared an Alert and proceeded to bring the unit to cold shutdown without any mejor complication (see paragraph 7). Unit 1 is presently in Mode 5, Cold Shutdown, commencing the refueling outage which was originally scheduled to start in mid-Apri The inspection period began with Unit 2 operating at 69% power, day 359 of continuous operation. On February 19, Unit 2 commenced a scheduled reactor shutdown for the refueling outage. This completed a continuous online run of.371 days of operation. Unit 2 is presently in Mode 6 with the fuel removed from the vesse North Anna Unit 2 was recognized as number one in the world for Westinghouse plants, number three in the world overall and number two in the for 1988 capacity factor. With the Unit 2 shutdown on February 19, Unit 2 set a company record of 371 days of continuous operation. Also, on that day Unit I had been operating continuously for 192 days, which sets a dual unit record for three loop Westinghouse plant . Mainhnance (62703)
Station maintenance activities affecting safety related systems and components were observed / reviewed to ascertain that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with Technical Specification The following details the inspector's findings / concern Auxiliary Feedwater Isolation Valve Maintenance On February 6, 1989, the inspector witnessed maintenance being conducted on AFW isolation valve 2-FW-HCV-200C per a generic Mechanical Maintenance Procedure MMP-C-GV-1.3. This maintenance was being conducted due to the failure of the valve to open fully during a surveillance tes The licensee immediately checked the air operated valve controller and positioner for the presence of oil or water; none were found. Maintenance personnel determined the problem to be a loose adjustment nut on the valve stem that had moved and prevented the air operated valve positioner from fully opening the valve. The adjustment nut was adjusted properly, and the valve was tested satisfactorily and returned to servic The inspector reviewed maintenance procedure MMP-C-GV-1.3, which requires the foreman in charge of the job to add ' write-in' steps providing the actions to be taken by the mechanic These steps essentially instructed the mechanic to disassemble the valve
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l positioner and controller, correct the pPoblem and reinstall, leaving the details of the work to the experience of the technician The inspector witnessed the maintenance and concluded that the experience of the technicians was sufficient to complete the work correctly.
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However, the inspector discussed with the licensee the need for more detailed ma.ntenance procedures and instructions, and greater guidance to the maintenance foremen on what . is required for the write-in steps of generic procedure Auxiliary Feedwater Pump Disassembly and Inspection Following the discovery of AFW pump problems at the Surry Station in 1988, North Anna Station management committed to the disassembly an inspection of several' of their AFW pumps during refueling outage The problems identified at the Surry Station involved reduction in discharge flow due to blockage caused by pieces of the impeller diffuser vanes cracking and breaking off. The North Anna Station has disassembled one motor driven AFW pump (2-FW-P-3A) and one turbine driven AFW pump (2-FW-P-2) during the Unit 2 outage. Just prior to the disassembly, the licensee performed head curve verification tests on the pumps (discussed in paragraph 4).
On February 23, 1989, the inspector observed portions of ' the disassembly of the Unit 2 motor driven AFW pump (2-FW-P-3A) per procedure MEMP-C-FW- On February 27, 1989, the inspector observed the disassembled AFW pump and reviewed associated test data. A review of the data indicated that all of the impeller bushing ring running clearances were out of toleranc The present acceptable tolerance is .009 to .014 and the readings varied from .016 to .01 The licensee stated that the "as found" clearances generally agreed with the original clearances as documented in a March 23, 1972 report. The licensee has requested that the pump vendor evaluate the dat The inspector will continue to follow this ite On February 28, 1989, the inspector examined the NDE (dyepenetrant)
tests that were performed on the 2-FW-P-3A and 2-FW-P-2 AFW pumps diffuser rings. The tests revealed that a number of the diffusers on both of the AFW pumps had indications of cracks, but none of the diffuser vanes had broken of Several of the diffusers showed ,
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erosion on the leading edge of the vanes, and there was also ,
indication of pitting on the diffuser surface. Based on the results !
of the inspections and tests, the licensee will replace several of I the diffusers on both pump Also, the licensee will be disassembling and inspecting the remaining Unit 2 motor driven AFW pump and all three of the Unit 1 pump The inspector examined the runout tests on the motor driven and turbine driven AFW pump shafts. The shafts had already been checked and the motor driven AFW pump showed no runout problems while the turbine driven pump showed .078 runout; a reading greater than .002 l is unacceptable. The licensee is attempting to locate parts to bring I
the pump tolerances within allowable range _ _ _ __- -_ _ _ _ __
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4 Service Water System Welkdown Maintenance Discrepancy During the walkdown of selected portions of the service water system on Unit 2, the inspectors noted that ~ the actuator assembly was l- missing on the 2-SW-214B MOV. There was a cloth bag present over the
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end of the valve stem, but there was no indication of the type of work in progress, or the location of the missing components. The inspectors contacted the operations personnel and were told that the .
valve was electrically tagged out at the MC The inspectors !
contacted maintenance personnel and determined that the motor for the valve was located in the electrical shop, on top of a file cabinet, behind a piece of red tape marked " Safety-Related". The remainder of the components were located in the mechanical shop in a drawer also marked " Safety-Related". The mechanics involved informed the inspectors that one of the components had been damaged during the disassembly of the actuator and that replacement parts were being obtained to allow the completion of the work and the restoration of ;
the valve actuator. The inspectors determined that the work was being performed in compliance with the approved station procedures, .
but stated a concern that there was no indication in the field of: the location of the components and the type of maintenance being performe Annual EDG Preventive Maintenance l On March 6, the inspector observed maintenance on the 2H EDG per Mechanical Maintenance Procedure MMP-P-EG- This maintenance was being performed to satisfy an annual preventive maintenance procedure DM-20-D/A-7, to disassemble and inspect clearances associated with the EDG blower. The inspector reviewed the procedure and noticed that the rotor to housing tolerance was 0.030 to 0.042 but the )
original measurement entry was 0.028. This entry had been lined out j and replaced with 0.0 The inspector questioned the mechanics and '1 was offered a demonstration of the gap measurement. The inspector {
was able to get a 0.03 feeler gauge between the rotor and the -
j housing, but in some places it was tight. This situation was discussed with the mechanics and the maintenance engineer in charge of EDG wor The inspector was informed that this blower had been overhauled previously by the vendor and a vendor's representative was on the site during the measurements and concurred that the tolerance measurements were acceptabl Within the areas 1nspected, no violations or deviations were identifie . Surveillance (61726)
The inspectors observed / reviewed technical specification required testing and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs were met, and any
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deficiencies identified were properly reviewed and resolved. Portions of the following surveillance were revieried/ observed by the inspecto Date Reviewed Surveillance Number Title 2/09/89 1-PT-17 Year Hydrostatic /
Pneumatic Test 2/14/89 2-PT-37 Radiation Monitoring Equipment Chec /19/89 2-PT-7 Auxiliary Feedwater Pump (2-FW-P-3B) and Valve Test 2/19/89 2-ST-52 Head Curve Verification (2-FW-P-2)
2/22/89 2-PT-61.3.2, Containment Purge Valves Attachment Type C Test As Fou1d 3/01/89 2-PT-6 Containment Depressur-ization Actuation Test 3/02/89 2-PT-5 Safety Injection Functional Test 3/17/89 2-PT-82.38 2J Diesel Generator Test The following problems / concerns were noted:
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On February 19, the inspector attended a briefing associated with the performance of 2-PT-71.3, Auxiliary Feedwater Pump (2-FW-P-3B) and Valve Test, and 2-ST-52, Head Curve Verification (2-FW-P-2).
Procedure 2-PT-71.3 was modified, and 2-ST-52 newly written, to allow performance of a head curve verification of the motor and turbine driven AFW pumps. The inspector noted that the briefing was poorly organized and not very well presented, but that the operators involved asked enough questions to determine the necessary actions that had to take plac The inspector observed the performance of both test With the exception of a recirculation flow problem on the 2-FW-P-3B pump, the licensee's recorded data indicated that both pumps fell very close to !
the manufacturer's suggested head curve and the preoperational test l data curv The low indicated recirculation flow problem on 2-FW-P-3B was corrected by isolating, for test purposes, leaking check valves associated with the oil coolers of the other pumps which had allowed flow to bypass the recirculation flow meter.
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On February 22, 'during 'the performance of 2-PT-61.3.2, the Unit 2 containment purge supply isolation valves failed to meet the acceptance value of not greater than 25 SCFH by leaking 100.8 SCF Attachment 3 of the procedure was then used to determine the leakage across individual valves. Removal of the flange on the discharge of containment. isolation valve MOV-HV-202 indicated no leakag Isolation valve MOV-HV-2008 leaked approximately 30 SCFH, which meant that the inside purge valve MOV-HV-200A was leaking approximately -
70.8 SCFH. The licensee will perform maintenance on these valves and retest them at a later dat On March 1, 1989, the . inspector observed the CDA Functional Test, 2-PT-66.3. The performance of 2-PT-66.3 was considered satisfactory; however, the_ inspector noted erratic flow indication for the service water provided to the RSHX. The inspector notified the licensee of the observation, and was informed that a special service water test was planned after the CDA test. The licensee conducted the test, and the results were unsatisfactory. The licensee suspects that the flow indicators were inadequate. During the performance of the test, the component cooling water to the residual heat removal heat exchangers was jumpered ou These valves will be tested separatel Verification of adequate service water flow to the RSHX will be identified as Inspector Followup Item (IFI 338,339/89-03-04).
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During ' the performance of 2-PT-57.4 on March 2,1989, the suction valve from the VCT (2-CH-2115-E) did not close and steam supply valves to the turbine driven AFW pump (2-MS-211 A/B) did not ope The licensee did not determine the reason for 2-CH-2115E failure to close; however, the licensee found that the steam supply valves were tagged to the close position at the auxiliary shutdown pane The valves were tagged during the outage when the turbine pump was removed for inspection. The licensee removed the tags and placed the switches in the auto position and the valves opene Also during the performance of 2-PT-57.4, the K-604 relay failed to reset following the resetting of the SI signal. This prevented the operators from being able to secure the low head SI pump 2-SI-P-1B and shut the high head SI suction valve from the refueling water storage tank, 2-MOV-21158. The relay was locally reset by the STA, allowing the operators to secure the pcmp and shut the valv The inspectors discussed the situation with the operations staff and test engineers, and determined that it is not uncommon for the K600 relays to stick dur.ing test situations. The inspector was informed that the STAS and operaters were knowledgeable on the methods required for manually resetting the K600 relays. The inspector discussed with the licensee the.need to determine a root cause for the relay sticking and provide corrective actions or provide procedural guidance to ensure operators take the necessary actions if a safety component cannot be secured or repositioned following an event. The licensee will continue to evaluate the problem associated with valve 2-CH-2115-E, and the corrective action to be taken for the sticking ,
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l 7 K-604 relay ;.roblem. Resolution of these issues will be tracked by Inspector Fo'lowup Item (IFI 339/89-03-05).
Within the areas inspected, no violations or deviations were identifie . ESF System Walkdown (71710)
The inspectors walked down accessible portions of the service water system in the Quench Spray Pumphouse Basemen The inspectors noted several discrepancies between the as-built configuration and the configuration delineated in drawings and procedure The discrepancies are discussed belo Vent and drain valves 2-SW-564, 565, 566, and 567 and 2-SW-72, 82, 92, and 102, respectively, had the opposite identification on the as-built configuration as the drawing. Valves 2-SW-72, 82, 92, and 102 are' actually located upstream of the 2-SW-MOV-203A, B, C, and D containment isolation valves in the locations shown on the drawing for valves 2-SW-564, 565, 566 and 567. Valves 2-SW-564, 565, 566, and 567 are actually located in the plant between the 2-SW-203 containment isolation valves and the containment penetration instead of outside of the containment penetration boundary as shown on the drawing. Licensee procedure, 2-PT-61.3, Containment Type C Test, uses the same diagram as the incorrect. plant drawings. During the last performance of this test, no procedure deviations were submitted on the associated sections identi fying these discrepancies, indicating the operators had not verified that the procedure and associated drawings were correc The Containment Type C test procedure was reviewed to determine if the drain valves 2-SW-564, 655, 566 and 567 were being leak checke This review indicated that the valves were leak checked but there was no requirement to check for valve packing leakage as conducted on other contair. ment isolation valves. Also, the licensee does not maintain control over the valve position and does not verify that the cap is installad downstream of these valves other than the check that is performed d Jring the Type C test every 18 months. The inspector questioned the licensee on how they were meeting the requirement in TS (TS 4.6.1.1.a) for these drain valves of verifying at least once per 31 days that all penetrations not capable of being closed by operable automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges or deactivated automatic valves secured in their position. The licensee informed the inspectors that they did not consider the vent and drain valves which are located inside the containment penetration boundary to fall under this requirement, consequently they do not comply with TS for these valves. This item will be considered as an Unresolved Item (338,339/89-03-03) pending further NRC revie l
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Valves 2-SW-80, 90, 100, and 110 are shown as being on capped drain lines upstream of tht radiation monitoring pump In act,alit these lines are hard piped to the floor drain Valves 2-SW-88, 98, and 108 are shown on the drawings as being on capped pipes. These lines were not capped, but had hose connections f installe Valve 2-SW-242 is shown as a capped vent line on one of the service water supply headers to the RSH The inspectors found the cap removed from the line. During the review performed by the licensee
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in response to this item, the vent valve was found to be open. A Station Deviation Report was written to address. tiis issu The Deviation Report and attached evaluation stated that the vent valve being open was not an operability issue and was not reportable. The inspectors found the cap off on February 6,1989. The last time the valve was independently verified to be closed and the piping capped was on the evening shift of February 4, 1989. Valve lineup procedure 1-OP-49.1A, Valve Checkoff - Service Water, and Unit 2 service water system drawing 11715-FM-0788 require the valve to be in the closed positio TS 6.8.1.a requires that written procedures be established, implemented and maintained covering operating procedures for safety-related system The failure of the licensee to comply with 1-0P-49.1A and drawing 11715-FM-078B in ensuring that 2-SW-242 was closed will be identified as a Violation (339/89-03-01).
6. Operational Safety Verification (71707)
By observations during the inspection period, the inspectors verified that the control room manning requirements were being met. In addition, the inspectors observed shift turnover to verify that continuity of system status was maintained. The inspectors periodically questioned shift personnel relative to their awareness of plant condition Through log review and plant . tours, the inspectors verified compliance .
with selected Technical Specifications and Limiting Conditions for Operation In the course of the monthly activities, the resident inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital areas access controls; searching of personnel, packages and vehicles; badge issuance and retrieval; escorting of visitors; patrols; and compensatory post On a regular basis, RWPs were reviewed and the specific work activity was monitored to assure the activities were being conducted per the RWP Selected radiation protection instruments were periodically checked and equipment operability and calibration frequency were verifie l
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The inspectors kept informed, on a de ly basis, of overall status of both units and of any significant safety matter related to plant operation Discussions were held with plant management and various members of the operations staff on a regular basis. Selected portions of operating logs and data sheets were reviewed dail The inspector:i conducted various plant tours and made frequent visits to the Control Room. Observations included: witnessing work activities in progress; verifying the status of operating and standby safety systems and equipment; confirming valve positions, instrument and recorder readings, annunciator alarms, and housekeepin On February 9,1989, the inspector observed the operation of the Unit 2 instrument air compressors which had recently been overhauled. The compressor was secured after a brief operation with no problem Following the Unit 2 compressor operation, both Units 1 and 2 instrument air compressors were both operated for four hour This performance run was successful, but both compressors were needed to maintain the instrument air pressure without the pressure control valve open and supplying service air makeup to the instrument air syste The inspector reviewed the lineup of the instrument air system in the turbine building with licensee personne The installed freon dehumidifier has been removed from service and a new dual unit desiccant system with coalescent filter has been installe A temporary diesel driven compressor has been installed as a backup to the Sullair compressor On February 19 and 20, 1989, the inspector witnessed portions of the Unit 2 shutdown to commence the refueling outage. The inspector spent most of the time in the control room observing the operator's actions in shutting down the unit. During the last SALP cycle, the NRC had noted a weakness in the licensee's programs and performance relating to going into, during and coming out of outage situations. The inspector observed that the operators were deliberate in their action Procedures appeared -
to be followed and when problems were encountered, the unit was placed in a stable condition and the problem was discussed and resolved prior to continuing with the shutdown. Also, as discussed in paragraph 11, the licensee conducted training on various operating procedures related to the outage including the shutdown procedure Consequently, the licensee completed the Unit 2 shutdown without major problem Within the areas'$nspected, no. violations or deviations were identifie . Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed reactor event and also the reactive event discussed in paragraph 8. The reviews included determination of cause, safety significance, performance of personnel and systems, and corrective action. The inspectors examined ,
instrument recordings, computer printouts, operations journal entries, l
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scram reports and had discussions with operations, maintenance and engineering support personnel as appropriat On February 17, 1989, the licensee declared a UE emergency classification for the Unit I reactor. This UE was declared because Unit I had developed an identified primary leak rate of greater than 10 gpm (actual 10.69 gpm)
and the operators had not been able to reduce the leak prior to exceeding the TS action statement limit of four hours. TS 3.4.6.2.b states , in part, that if the identified leak rate exceeds 10 gpm, reduce the leak to less than 10 gpm within four hours or be in hot standby in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. However, the licensee was able to reduce the leak to less than 10 gpm (~3.5 gpm) prior to exceeding the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and a complete shutdown was not require The problem with the increased primary leakage was first discovered by the control room operator on February 16 at approximately 2:00 p.m. At that time, the operator noticed an increase in the reduction rate of the VCT and an increase in the fill rate of the PDTT. A primary leak rate calculation was initiated and at 2:40 the identified leak rate was determined to be 10.6 gpm. The licensee entered the required TS action statement and was able to reduce the leak rate to less than 10 gpm by isolating normal letdown and initiating excess letdow The first entry into the TS action statement was exited at 4:45 p.m. on February 16 with a leak rate calculation of 9.4 gp The licensee conducted several entries into the Unit 1 containment and determined that the most probable cause of the increased leakage was a packing leak on RC-63, RTD bypass line isolation valve in the B RCS loo This determination was made based on the increased temperature of the packing leak off line from RC-63 to the PDTT. Based on the location of the valve and the general area radiation dose rate, the licensee decided i to reduce reactor power to 30*/' prior to attempting to backseat RC-63. The l power reduction was completed on February 17 at approximately 1:52 a.m.
I j During this event, the licensee continued to conduct leak rate l calculations and, as stated above, at 7:13 a.m. on February 17, the
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identified leak rate again exceeded 10 gpm (10.69). The licensee entered the TS 3.4.6.2.b action statement for the second tim Even though the licensee suspected that the problem was a packing leak on RC-63, actually obtaining access to the valve to stop or reduce the leak was very difficult due to the physical location of the valv Since the containment is subatmospheric, operators must wear air bottles and respirators to enter containmen Also, since the valve in question is located in the B loop room, below the deck of grating of the level closest to the valve and considerably above the next level, the operator must remove the bottle from his back, remove the deck's grating and crawl down under the grating to the valve. This evolution took several entries into containment to set up the valve adjustment and required the licensee to expend considerable time in planning to ensure protection of the operato Consequently, the licensee was unable to reduce the leak to less than 10 gpm prior to exceeding the TS requirement of four hours. Because the leak
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was.not reduced within the four hour action limit and because reactor power had been reduced earlier in the night to reduce the radiation levels at.RC-63, the licensee declared a U Very shortly after exceeding the four hours, an operator was able to obtain access to RC-63 and backseat the valve along with adjusting the packing gland. .The control room operators noticed an immediate change in the slope of the level increase of the PDTT, indicating that the leak rate had been reduced considerably. However, the licensee did not exit the TS action statement and UE for approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> until a fully verified primary' leak rate calculation confirmed the reduction. This calculation was completed at 2:04 p.m. , indicating that the identified primary leak rate had been reduced to approximately 3.5 gp The inspector witnessed the event during the times.when the unit was in the TS action statements and the UE. The inspector observed that the operators were alert and identified the situation quickly. The follow-up actions taken were appropriate and timel Station management was involved with the development of the corrective actions and concurred on the containment entries and attempts to backseat RC-63. The only problem noted by the inspector involved the continued use by the operators of the old composite type system drawings. The operators used these drawings for reference because the new controlled drawings are the CADS which break a full system down into several sheets, making it difficult to get an overall view of the system. The licensee allows the old type drawings to remain in the control room for reference purposes only, since these drawings are not updated. The licensee committed to determine the actions necessary to make the new CADS more usable for the operators and to eliminate the outdated drawings. The inspector will follow up on the licensee's actions and this item will be identified as Inspector Followup Item (IFI 338,339/89-03-06).
8. Steam Generator Tube Leak Event (93702)
At 2:07 p.m. on February 25, 1989, while at 76% power, Unit 1 automati-cally tripped due to a S/G flow greater than feedwater flow mismatch coincident with low S/G level. The mismatch resulted from the closure of the 1C S/G main feedwater regulating valve due to fatigue failure of the instrument air supply line around the fitting on the valve positione Following the reactor trip, the operators noticed that RCS pressure was not increasing at the rate expected and more charging flow than expected was needed to restore and maintain pressurizer leve .
At 2:26 p.m. on February 25, Hi and Hi-Hi alarms were received from air ejector radiation monitor 1-RM-RMS-121. The operators entered abnormal procedure 1-AP-24.1, Large Steam Generator Tube Leak Requiring Immediate and Rapid Unit Shutdown, identified the IC S/G as the source of primary to secondary leakage, initiated emergency boration, and isolated the 1C S/G steam supply to the turbine driven AFW pump. The leak was estimated to be 60-70 gpm, based on charging and letdown flow rates, and the licensee declared an Alert emergency condition at 3:25 p.m. on February 25. At
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4:00 p.m. on February 25, the RCS pressure was reduced below the IC S/G pressure, and the IC S/G level began decreasing. The plant entered Mode 4 at 5:33 p.m. and the RHR system was placed in service at 9:43 The following provides the inspectors' assessment of the February 25 S/G tube leak in the areas of: a) usability of selected emergency / abnormal procedures, b) sequence of events as documented by the licensee, c) licensee's implementation of Generic Letter 88-17, and d) radiological aspects of the primary to secondary leakage. Additional details regarding the primary to secondary leak are contained in NRC Inspection Repcet 338, 339/89-0 Emergency Procedures and Abnormal Procedures The licensee's EPs are based on the WOG Rev. I generic procedure Each step of the EPs which deviates from the WOG is justified in a step deviation document. In addition, several steps were changed in anticipation of the issuance of Rev. IA to the WOG procedures. The completion of the changes required by Rev. 1A is targeted for July 198 The inspector reviewed selected emergency and abnormal procedure Selected steps of the EPs were compared to the WOG guidelines, and were examined for conformance to WOG's accident mitigation strategy guidance and compared to the steps taken by the operators during the February 25, 1989 tube leak event. In a small number of cases, the inspector reviewed the justification for step deviation In addition, the inspector examined the relationship between trie EPs and the APs with respect to this event. The inspector's conclusion was that the operators demonstrated an excellent understanding of the accident mitigation strategy, conformed literally to the guidance of the EP while in it and successfully selected the appropriate AP when outside the EP when these choices were made necessary by changing plant condition On the other hand, the inspector found the EP/AP interface to be l- weak. The reason for the weakness is that the process of exiting I from a symptom based EP to an event based AP requires an unnecessary and undesirable shift in the reactor operator's thinkin In the more commonly envisioned major accident scenario, this is less of a concern than in the current case where the leak was large enough to require entry into the EP but only for a short tim The major portion of the time of the incident required mitigation by the AP In addition to the interface problem, ever,t based APs (as is common)
are an undesirable accident mitigation too < Sequence of Events The sequence of events, as developed by the licensee over a period of several days, is portrayed by the written description and parameter trends in Appendices 1 and 2. The inspector examined the validity of
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these until satisfied of their accuracy by interview and document compariso In addition, the actions of the operators, support
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personnel, and instrumentation and equipment were c.1tically examined and questioned. The inspector concluded that the operator responses to the tube leak event ranged from acceptable to commendable. At the-acceptable end of the spectrum was the decision not to manually initiate safety injection as the pressurizer level approached tha.
l initiation set point at a decreasing level. At the commendable end of the spectrum was their excellent communication among all involved parties which led to a very systematic and deliberate set of action A weakness in equipment design and support personnel procedures was graphically demonstrated by this sequence of events. Early on, the operators recognized the need to determine and then substantiate that the event in process was a S/G tube leak. Furthermore, once that was done, it was necessary to determine which generator was the affected generator. The instrumentation and methods classically available: at North' Anna for these purposes are: N-16 monitors, steam relief line radiation monitors, S/G blowdown samples, air ejector rad monitors and air ejector exhaust samples. In the February 25 tube leak event, the following monitors were rendered ineffective - the N-16 monitors by the early cessation of steam flow, the steam relief line monitors by the fact that the reliefs did not lift and the activity of the reactor coolant was not excessive, the S/G blowdown sampling by.the isolation of blowdown on low-low S/G level (the tube leak in .the faulted generator was too small to keep the level .above the low-low level isolation), the air ejector rad monitors by equipment failure, and air ejector exhaust samples due to problems encountered by HP in obtaining samples in response to the operator's request at 2:26 In addition, the response of chemistry to the 2:26 p.m. request was not timely (54 minutes total, 40 minutes after unisolation of blow-down). To the credit of HP, they did provide the one definitive identification of the faulted S/G by teletector monitoring of the steam lines in response to an operator's suggestion. This is not suggested by an AP, but ,is the result of alert and cooperative ,
personnel in HP and operations, c. Generic Letter 88-17, Loss of Decay Heat Removal The general requirements of Generic Letter 88-17, as well as the licensee's commitments made in response to that letter, were reviewed by the inspecto The generic letter concerned lowered loop operation, i,e. operation of the shutdown cooling system with water level lowered to the centerline of the hot leg. Although lowered loop operation was not within the sequence of events depicted by Appendices l'and 2, this operation may be necessary in the future at North Anna. The training, procedures, and equipment commitments made in response to the generic letter all appear to be adequat The training portion of this response was excellent. A detailed review of this Generic Letter will be conducted and documented in subsequent inspection report ~ t,
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14 Radiological Aspects Environmental As the .HP group was notified of the primary to secondary leak and became involved in the event, pathways for release of radionuclides to the environment were examined. Since the PORVs and the Main Steam Safety Valves were not used or activated during the event, it was assumed that neither of those potential pathways needed to be-considered as contributing to a potential offsite release. Through review of instrumentation indications and system functions, two major pathways were identified: 1) the plant ventilation exhaust and 2) the turbine driven AFW pum For the ventilation exhaust, a release pathway existed from approximately 2:26 p.m. to 3:13 p.m. due to activity being released through the CAE and into the ventilation exhaust. At 3:13 p.m. the CAE discharge was manually diverted to containmen Following the diversion, activity continued to be discharged via the plant ventilation exhaust pathway as indicated by the plant ventilation exhaust stack radiation monitor readout in the control room. The licensee indicated that this was activity that apparently had been released to the Auxiliary Building. The total activity, as indicated by. the ventilation exhaust radiation monitor, decreased as it was removed from the Auxiliary Building to the atmosphere by the ventilation syste This release pathway, therefore, continued to exist until 5:24 p.m. (for a total duration of 178 minutes) when the ventilation exhaust radiation monitor showed a reading similar to that before the event. The pathway from the turbine driven AFW pump exhaust was determined to exist from 2:07 p.m. , when the AFW pumps were automatically started, until 2:40 p.m., for a total release time of 33 minutes. At that point in the event, the steam supply to the AFW pumps was manually isolated and the release via the AFW pump exhaust terminate .
The licensee used the strip chart recording from the Kaman Vent Stack
"A" Normal Range Effluent Monitor RM-VG-179-1, taken during the event, to determine the activity released through the CAE and the exhaust stack. While this release pathway existed from 2:26 until 5:24 p.m., the majority of the activity was released between 2:26 p.m. and 3:17 p.m. and the maximum release occurred between 3:04 p.m. and 3:11 p.m. as indicated by the Kaman strip chart. In order to be , conservative, the licensee assumed the maximum release rate to have occurred from 2:26 p.m. to 3:13 p.n. and the total time for the release to have occurred from 2:26 p.m. to 5:24 p.m. or almost 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The total activity released was determined by manually integrating the stack monitor strip chart release rate curve. This data, in conjunction with the isotopic analysis of a grab sample taken from the CAE exhaust, yielded a calculated total release of 4.80 curies of noble gases through the plant vent exhaus :t,
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Since the t trbine driven AFW pump exhaust monitor did not indicate any activi.y significantly above background (approximately. 0.02 millirem per hour), the licensee was not able to use data from this monitor to calculate the release from this pathway. Instead, the licensee used the release rate indicated by the Kaman monitor, in conjunction with the results of the isotopic analysis of the CAE sample taken at 2:55' p.m., and the estimated steam flow rate of the turbine driven AFW pump to determine the amount of gaseous activity
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released through the turbine driven pump. It was assumed that during the time of the event, the release recorded by the Kaman monitor in the stack from the CAE prior to CAE diversion to containment was representative of the release rate of noble gases from the turbine driven pum Since both CAE and the turbine. driven pump take steam from the S/G main steam header, and since these two routes represented the majority of steam flow for the plant at the time of the event, thic assumption appeared to be conservativ Using these data,-the total activity released' through the turbine driven AFW pump exhaust was determined to be 0.475 curies of noble gase Tritium, particulate and halogen components of the turbine driven AFW pump release were also considered. .These activities were determined using the radionuclides distribution determined from S/G blowdown samples taken at 2:50 p.m., a release duration of 33 minutes, and th turbine driven pump steam flow rate. The licensee determined that the release from this pathway was 0.01 curies of tritium and 1.40E-7 curies of particulate and halogen activit For all release pathways, a total activity of 5.29 curies was released, 5.28 curies of which were in the form of noble gases. The predominant radionuclides (in descending order of activity released)
were Xenon-133, -135, -135m, -133m, and -138, Krypton-88, -85m, and-87, and Argon-4 Dose rates, calculated based on the estimated maximum release rates for the CAE and AFW pump exhaust, were determined to be within TS allowable dose rates at and beyond the sit These dose rates, measured in millirem per year (mrem /yr), were as follows:
TS Dose Rate Limit Event Dose Rate % of TS (mrem /yr) (mrem /yr)
Whole Body 500 12.00 2.30 Skin of WB . 3000 24.00 0.82 Critical Organ 1500 0.03 0.002 Inplant and Offsite Monitoring During the event, environmental monitoring teams were dispatched both offsite and onsite to provide data for determining the magnitude of the release and for performance of dose projections. Radiation levels, removable contamination levels and air sample results were i
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4 obtained. However, o detectable activity above . background was observed from any of these media. Additionally, radiation level, removable contamination level, and air sample-surveys in the TSC and the Operations Support Center during the event confirmed no radiation or airborne radioactivity 'above background was present 'and no-contamination was detecte Only minor radiological consequences were observed inplant during and subsequent to the event. When it was evident that releases were occurring, air samples were obtained t various locations throughouc the olant. Examination of the air sample log showed that inplant airborne activity seldom exceeded 25 percent (%) of the MPC of radionuclides specified in 10 CFR 20, Appendix B, Table 1, Column At 3:25 p.m. however, the activity in the Turbine Building rea: Sed 34% of MPC. 'The entire building was subsequently posted and controlled as an airborne radioactivity area until further samples confirmed that the airborne activity had dropped below 25% of MP At 6:43 p.m., the activity increased to nearly 17 times MPC for a brief period in the sample sink area of the Auxiliary Building during a purge of the sample lines. This area, too, was controlled as an airborne radioactivity area until further air samples indicated that the airborne activity was below 25% of MP Smear surveys taken throughout the Turbine and Auxiliary Buildings showed no detectable activit Radiation level surveys in these areas during the event indicated that radiation above background levels was not detectable except for a small area around the "C" main steam trip valve. Contact readings on the valve were found' to be 5 mrem /h Radiation level readings from the previous day had indicated a radiation level of 0.02 mrem /hr. This area was posted and controlled as a radiation are Radiation Monitors Following the reactor trip at 2:07 p.m., a radiation alert alarm was received on the main steam line at 2:08 The alarm was .
acknowledged and cleare The Unit 1 shift supervisor then checked ) '
the main steam line radiation monitors and normal readings were noted on all steam lines. No indications of a S/G tube problem were received until 2:26 p.m. , when CAE radiation monitor (1-RM-SV-121)
high and high-high alarms were received. Because the air ejector !
radiation monitor indicator was swinging erratically, the procedure i 1-AP-5.1, Un:lt 1 Radiation Monitoring System, for abnormal operations was entered and HP was directed to sample tne air ejector exhaus Chemistry was also directed to sample S/G blowdow The STA checked other radiation monitors for indications of a primary to secondary leak. Blowdown radiation monitors, however, did not indicate an increase in activity since blowdown was isolate N-16 radiation monitors did not indicate an increase in activity since the reactor had trippe The only indication of a problem was the "C"
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17 j main steam line radiation monitor-. It showed a slight increase in activity: 0.15 mr/hr as opposed to a normal reading of 0.04 mr/h "A" and "B" main steam line radiation monitors showed no' increas The CAE radiation monitor continued to swing erratically and HP reported problems sampling the ejector exhaust because of water in the lines. Water was also cited as causing the erratic CAE radiation monitor readings, The CAE radiation monitor continued to give erratic readings until the CAE exhaust was manually diverted to containment at 3:11 p.m. After that time the CAE radiation monitor indicated a continuous high-high alarm. At 2:48 p.m., a high radiation alarm was received c.1d cleared on the ventilation vent "A" stack monitor and at 3:06 p.m., a high-high alarm was received on the IC S/G blowdown monitor (which had been returned to service). No alarm was ever received on the turbine driven AFW pump monito Upon reviewing the problems noted with the radiation monitors during a similar S/G tube rupture event which occurred in 1987, the inspector noted that the same CAE radiation monitor, 1-RM-SV-121, had been declared out of service during the time of that even Two violations were cited in conjunction with the inoperability of the CAE monitor. These violations dealt with failure to take corrective actions to verify operability of the monitor and failure to perform
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adequat? operability channel checks on the monitor as required by Technical Specifications. In response to one of the violations, the licensee indicated that the source of the problem with the CAE radiation monitor the day prior to the 1987 S/G tube rupture had been moisture in the monitor lines. The lines were subsequently drained of the moisture and the monitor returned to service. Later, however, the monitor failed due to an unrelated proble Through a review of maintenance records and interviews with licensee representatives, the inspector determined that, although the problem associated with water in the monitor lines had been identified in 1987, no further problems of that nature had since been documente However, the inspector also determined that no actions had been taken to assess the root cause of the problem with water in the lines or correct the situatio CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that measures be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, ;
defective me.terial and equipment, and nonconformances are promptly
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identified and correcte In the case of significant conditions adverse to quality, the measures shall assure that the cause of this condition is determined and corrective action taken to preclude repetition. Failure of the licensee to determine the root cause of ,
the problem encountered with the CAE radiation monitor in 1987 and l failure to tah corrective actions to preclude repetition of the problem, which resulted in erratic response of the monitor during the L
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. Feoruary 25, 1989 S/G tube failure event, is identified as a V alation of 10 CFR 50, Appendix B, Crit.:rion XVI (338/89-03-02). Licensee Event Report Follow-up (90712)
The following LERs were reviewed. The inspector verified that reporting requirements had been met, causes had been identified, corrective actions appeared appropriate, generic applicability had been considered, and the LER forms were complet Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations o regulations or TS conditions had been identifie (Closed) LER 339/87-004, Missed Surveillance Steam Generator Gross Activit Although the surveillance requirement was missed, data from the daily air ejector couats, isotopic printout of the S/G blowdown, and S/G gross activity determinations provided evidence that no gross activity limit was exceeded on the event date. The inspector verified that the Chemistry Department has revised its policy to include sign-offs avery 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (every shift) for chemistry 3 surveillance. The licensee's Chemistry Department personnel were 1 instructed on the new sign-off polic (Closed) LER .339/87-007, Missed Surveillance - Low Pressure CO2 System. Periodic test 2-PT-102.1, Low Pressure CO2 Total Flooding Surveillance Test, was added to the Periodic Test Scheduling Syste A complete review was also performed on the PTSS to. determine if any other surveillance were not on the system. Two additional periodic tests were added to the system as a result of the review. No other problems were found with the scheduling syste (0 pen) LER 339/87-009, MSSV Set Pressures Not Within TS Limits. All MSSVs were refurbished and retested by Wyle Labs until the set pressures were' within the allowable limits of TS 3.7. None of the valves leaked during the final leak test following inspection, cleaning, lappim d refurbishment. The licensee submitted ,
supplemental LER u -u09-01 on January 21, 1988 which provided a detailed report of the Wyle Lab findings and repairs made to the MSSV No root cause was determine As an additional corrective action, an engineering feasibility study is currently being performed to determine if the tolerance for the MSSV setpoints can be increase If additional tolerance can be justified, the licensee will consider requesting a change to TS 3.7.1.1. Th'is LER will remain open pending the results of the MSSV engineering feasibility study which is due June 30, 198 (0 pen) LER 338/87-015, Reactor Trip Due to 5A Feedwater Heater High-High Level. The root cause for the improper air system valve line-up was determined by the licensee to be failure to follow administrative controls for hanging and removing danger tags and returning valves to servic The inspector verified the corrective
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actions taken to date. The licensee presented lessons learned from the event ;o operations personnel and has perfor,aed an air system valve line-up procedur This LER . will remain open until the licensee has completed the instrument air va'lve lineup in the Unit 2 containment. The licensee has extended the due date for this item to July 31, 1989, (Closea) LER 339/87-016, Inadvertent RPS Actuation During Testin The licensee revised 1-PT-71.4 and 2-pT-71.4 prior to the next scheduled performance of the test, which should preclude recurrence of this even This item was the subject of violation 338, 339/87-36-0 (Closed) LER 339/87-018, Inadvertent EDG Start During Testing. The licensee attributed the cause of the event to personnel error. The electrician involved failed to follow the procedure and did not reverify that he was working in the correct test cabinet prior to performing an Undervoltage Periodic Test on the "2H" Emergency Bu As a result of the event, color coded unit and train identification has been provided on the inner and outer doors of the Service Water Logic Cabinets. In addition, the licensee revised periodic test procedure PT-36.9.1 H/J to require a second verification of the train being tested. These procedures now also include cabinet and circuit numbers for all components used in undervoltace prctection system testing. This item was the subject of IFI 335/87-42-0 (Closed) LER 338/87-021, Loss of Environmental Qualification of SI Accumulator Tank Pressure Transmitters. Nuclear Design Control Program procedure, STD-GN-0C01, Instructions for DCP Preparation, was revised to provide additional guidance and instructions for DCPs which require the installation of equipment per the manufacturer's installation instruction The licensee also developed a generic procedure, IMP-C-1-PROC-02, to repair or replace Rosemount transmitters of the type involved in this even (Closed) LER 338,339/87-024, Vent Stack "B" High Range Radiation
' Monitor Exceeded T3 Action Statement. The Kaman Vent Stack "B" High Range Radiation Monitor (RI-VG-180-1) was declared inoperable on December 4,1987, due to a damaged PROM. On December 3,1987, the licensee installed a new PROM and Central Processing Unit card in the Kaman Process Vent Low and High Range Radiation Monitors and the Vent Stack "A" and "B" Low and High Range Radiation Monitors to correct a previous unr. elated proble The manufacturer of the failed PROM was inconclusive as to the origin of the damage, whether improper lab testing or field handling was the root caus However, the manufacturer did state that upon occasion, PROMS that test satisfactory do not necessarily perform as required in the fiel _ - - _ _ _ _ - _ _ - _ - _ _ _ _ _ ___ ._ . _ .
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l 20 (Closed) LER 338/8P 001, Vent Stack "A" Normal Range Radiation Monitor Exceeded T.S. Action Statement. The scintillator t.oe in the monitor was replaced and insulated electronically from the detector housing. This restored the monitor to operable statu (Closed) LER 339/88-002, Inadvertent ESF System Actuation. This ESF actuation was caused by an incorrectly installed relay cover. The licensee revised the procedure affected to ninimize the removal of relay covers when contacts could be verified from the terminal board The electricians that perform this procedure have been traine . (Closed) LER 338/88-004, Resin Intrusion into the Secondary Side Water Syste The licensee developed procedures for the proper installation of the filter elements and for the testing for resin leakage. The operations procedure for the filter vessels was revised to allow operation with a more compact precoat and to require compliance with the maximum number of resin particle The licensed operators received additional training in the operation of the powdex syste j (Closc ') Lt!R 339/88-004, Revision 1, Both Emergency Diesel Generators '
Inoperable at the Same Time. An Operations Standing Order was implemented which requires verification that the charging springs are charged following operation of the breake The Preventative Maintenance procedure for 4160 volt breakers has been revised to require more frequent periodic inspection of the charging motor and verification of the correct tightness on the charging motor mounting bolts, (Closed) LER 338/88-005, Automatic Reactor Trip Due to Hi-Hi Steam Generator Level. The licensee revised Operating Procedure 2.1, Unit Power Operation Mode 2 to Mode 1, Revision 31, to include cautions about feedwater temperature and increasing power above ten percent with S/G level oscillation (Closed) LER 338/88-006, Vent Stack "A" Radiation Monitor Exceeded TS Action Statement. To improve the reliability of the monitors, the licensee is performing a root cause analysis for the failed flow inverter cards and is modifying the Stack Vent Radiation Monitors in accordance with recommendations from the manufacture (Closed) LER 338/88-011, Post Modification Testing Not Performed as Required by Two Technical Specifications. The licensee revised Administrative Procedure ADM-3.7, Engineering Work Requests, to control post maintenance acceptance test procedure development and test performance documentation criteria for Engineering Work Request (Closed) LER 338/88-014, Reactor Trip Due to "C" S/G Level Signal .
The trip signal occurred with the unit in Mode 3 and the reactor trip
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breakers open while instrumr-tation technicians were calibrating steam flow instrumentation The licensee revised all affected instrument' calibration procedures to have the bistables placed in the j trip condition only when it is necessary to perform the required I calibration, (Closed) LER 338, 339/88-016, Recirculation Spray Heat Exchangers Not Placed.in Dry Layup as Stated in the UF3AR. Analysis of the fouling present prior to the chemical cleaning of the RSHX tubes determined that the heat exchangers would have been able to pass the amoat of heat required by the accident analysi Periodic test procedure, 1-PT-62.2.1, RSHX SW Inleakage, was revised to include . periodic checks and drainage of any inleakage to the RSHX Instrument calibration procedure, ICP-P-1-BP-2, Recirculation Spray Heat Exchanger Outlet Flow, was developed to maintain accurate process instrumentation to detect excessive leakage to the RSHX (Closed) LER 339/87-017, Nuclear Instrument Channel Not Placed in Trip Within 1 Hou Periodic test procedures, 1-PT-94.0' and 2-PT-94.0, Refueling Nuclear Design Check, were revised to assure that the detector channel is appropriately placed in trip, as required by the T Periodic test procedures, 1-PT-30.2.4 and 2-PT-30.2.4, NIS Power Range Channel IV (N-44) Functional Test, were revised to include a note stating that if the N-44 detector channel is being tested prior to physics testing, the channel must be left in tri . Station Drawing Review *
The controlled drawings located in the control room and listed in Attachment 1 of Administrative Procedure ADM-3.12, Redline of Control Room Drawings, are considered to be the critical drawings for the operator These drawings were reviewed for clarity by the inspector Most of the
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drawings, specifically the new CAD drawings, had excellent clarit Because of past prcblems with new drawing copies of poor clarity being i distributed to the control room, an Operations Coordinator is required to review the new drawings prior to placing them in the control roo In two cases reviewed, the inspector noted that the drawings had rejection stamps on them stating they were rejected by the Operations Coordinator and a ,
, design update request had been submitted on January 24, 198 When I questioned, the Operations Coordinator explained that these were the best prints available at the time and when a better quality drawing is l available these drawings will be replace The inspector questioned the operators concerning the stamp on each drawing which lists the DCPs, EWRs and DURs identification numbers that affect the particular drawin The response received was varied indicating that the information located in the stamp on the drawing was not fully understood by the operators. This stamp is intended to provide the operator with information concerning any modification planned or in progress and any other discrepant condition whic5 would affect the
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22 drawing. However in the case of modifications, the drawing is supposed t be updated by either redlining the present drawing or replacing the drawing with a new revision, within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of the modification being placed in operatio Based on the inspector's observations and discussions with the licensee, the Operations Coordinator sent out a memo to the operators dated February 21, 1989, which listed the administrative procedures that covered the' subjec Also, the licensee informed the inspectors that they are in the process of changing the method for annotating drawings with information concerning modifications or discrepancies. The inspectors will review the new method after it has been implemente As stated in NRC Inspection Report 338,339/88-36, the inspector reviewed the drawings in the TSC and Control Room and discovered that the TSC drawings were not being maintained up to date on the same priority as the Control Room drawings. The inspectors determined that the licensee's procedures did not require the TSC drawings to be updated at the same time as the Control Room drawings. The licensee informed the inspectors that the TSC drawings have been reviewed and updated to the same revision as the Control Room drawings. The inspectors reviewed new revisions to ADM-3.12, Redline of Control Room Drawings, ADM-3.14, Drawing Update Request, and ADM-6.10, Annotation and Revision of Station Drawings, all dated February a, 198 These procedures now require the TSC drawing hard copies to be updated at the same time as the Control Room drawing The inspectors reviewed the licensee's methods and procedures for updating drawings due to identified discrepancies and design changes or modifications. ADM-3.14 describes the method for plant personnel to identify and correct any discrepancies found on controlled drawings. The present procedure, dated February 28, 1989, requires that a DUR be initiated by the person identifying the drawing discrepancy, and the cognizant supervisor review the request and then forward the request to the Design Control Engineering Group, where it will be reviewed' and assigned a DUR log number. The inspector reviewed a number of drawings which indicated that DURs had been submitted but no date was listed to enable the inspector to determine how old the DUR was. After a review of ADM-3.14 and a discussion with licensee, the inspector determined that there was no time limit on how long a DUR could remain outstanding. The inspectors considered this to be a weakness in the drawing update program and requested the licensee evaluate their program and make necessary change ADM-6.10 describes the method for updating anri revising station drawings due to discrepancies, design changes and modifications. This procedure originally required priority drawings to be redlined within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of a design change or modification being technically reviewed and placed in operation. There were a number of cases identified by both the inspectors and the licensee where design changes for one reason or another were not annotated on the controlled drawings in the control room even though the equipment was already in servic Inspection Report 338,339/88-33, l
paragraph 6, " Operational Safety Verification", identified problems with
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F 23 red lining of control room drawings and a Violation-(3'"3,339/88-33-02) was q issued. After the inspectors found the initial problems with the service water system (discussed in paragraph 5), the licensee proceeded to do their own review and identified in deviation report 89-214 the failure to incorporate a DCP in the service water drawings. Drawing numbers 11715-FM-786 Sheet 1 and 2 did not reflect the addition of the service water alternate supply header to both unit charging pumps. These control room drawings were neither revised or redlined as required by ADM-3.1 As a result of the problems initially identified in Inspection Reports 338,339/88-31 and 338,339/88-33 that involved configuration control problems and the failure to include some design changes in control room drawings, the licensee decided to consolidate the station drawing control and update responsibilities under the PES group. PES will also assume the responsibility for the distribution of revised drawings to the Control Room and TS To facilitate this, the custody of station original drawings will be transferred to Power Management Services, Innsbroo Following this transfer of responsibility and the additional drawing .
discrepancies identified in this inspection report, PES has revised the procedures that control the drawing update program. As stated above, the inspectors have reviewed these procedures and as a result have discussed with the licensee the need for further evaluation of the drawing update ;
program to address the confusion concerning which drawings will be red )
lined and associated timelines In addition to those identified by the NRC, the licensee has also identified a number of discrepancies between as-built systems and their associated drawings. To date, none of these discrepancies have resulted in a major safety concern or contributed to a major event. However, there are enough minor discrepancies to bring into question the accuracy of the station drawings. The inspectors have walked down most of the safety systems in past inspection efforts and have not identified any major problems with the main system flow path Consequently, the concern relates mainly to less safety significant systems and components,.
especially infrequently used systems and components. The licensee has .
informed the inspectors that an evaluation is being conducted to determine a plan of action to resolve the issue concerning the question of accuracy of the station drawing The inspectors will continue to monitor the-licensee's actions to resolve the problems concerning the drawing update program and the accuracy of the drawings. This will be identified as an Inspector Followup Item (IFI 338,339/89-03-07).
1 Preparation for Refueling (60705)
The inspector attended one of the training sessions covering various aspects of the upcoming refueling outage. Tnis particular training session was required to be completed bv all licensed operators prior to the refueling outage. The session lasted for approximately four hours and covered the following procedures:
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2-AP-11.1 Malfunction of RHR 2-AP-11.2 Loss of RHR 1-0P-3.3 Unit Shutdown from Hot Shutdown (Mode 4) to Cold Shutdown (Mode 5) less than or equal to 200 degrees F.~
1-0P-3.4 Unit Shutdown from Cold Shutdown Condition (Mode 5) less than or equal to 700 degrees F to Cold Shutdown (Mode 5)
less than or equal to 140 degrees F and less than or equal to .95 K effectiv OP-5.4 Draining the Reactor Coolant System The training instructors also presented discussions on'the Diablo Canyon loss'of RHR and other related events. Along with the presentation on loss of RHR the instructors discussed North Anna's response to Generic Letter 88-17 and the steps that have been taken to prevent the occurrence of loss of RHR at the North Anna Power Station. One of the steps involved the initiation of a new procedure, 1-MISC-37, Assessment of Maintenance Activities for Potential Loss of Reactor Coolant Inventory. This procedure was presented to the operators for training purposes along with a discussion on an actual event involving the loss of reactor coolant inventory which occurred on North Anna Unit 1 during the 1987 refueling outag The inspector felt the training staff did an excellent job with the time allotted, and that more time was needed to completely cover all the material, considering the magnitude of changes to procedures. During these training sessions, problems were identified by the operators concerning inadequate or incorrect procedure steps in some of the new and modified procedures. These problems were corrected by the issuance of procedure l change ;
Following the first four hour session, a second four hour session was given at the simulatur to practice cooldown and malfunction of the RHR system. The inspector did not attend the second four hour session, which allowed the operators to practice centerline operation including installation of the tygon tubing reactor vessel level indication. However -
i the inspector was made aware that the licensee has made an effort to eliminate operation at vessel nozile centerline conditions except where absolutely necessary for maintenanc The inspector completed a review of 2-OP-4.1, Controlling Procedure for Refueling. This procedure is the master controlling document for all the !
refueling activit,ies that take place during the outag i Within the areas inspected, no violations or deviations were identifie . Cold Weather Preparations (71714)
The inspectors performed a review of completed procedures related to the winterization program at the plant and performed a walkdown of areas that had the possibility of being impacted by cold weathe Plant procedure,
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1-MISC-18, Cold Weather Operations, identifies areas where problems have been encountered in the past and requires that the operations personnel increase awareness of the condition of these areas during times of adverse weather. The procedure was completed October 13, 1988 and has remained in effect since the Maintenance procedure MD-ADM-20.0, Plant Winterization Program, directs the preparation of various systems for cold weather. The nlant preventive maintenance program includes procedures that periodically serify that the winterization program has maintained the required actions in effect. The l inspectors verified that this program had been maintained, as require l l
Within the areas inspected, no violations or deviations were identifie . Licensee Action on Previous Inspection Findings (92701 and 92702) (Closed) Violation 338,339/87-15-01, Violation of TS 3.6.1.1., !
Containment Integrity. The inspector verified that the approved TS change (Amendment Nos. 98/85 and 82) for Table 3.6-1 was incorporated into the licensee's TS. This change designated, by asterisk, the hydrogen recombiner isolation valves in TS Table 3.6-1 as valves which can be administrative 1y controlled during surveillance testin The inspector also reviewed Periodic Test Procedures PT-68-1.1, PT-68-1.2, PT-68.2.1, and PT-68. These have been revised to add a precaution to instruct the control room operator to secure the hydrogen recombiner and then close the recombiner remote isolation valves if a containment isolation signal is generated while the functional test is in progres The inspector has no further concern (Closed) Violation 338/87-24-03, Failure to Perform Adequate Operability Channel Checks on Radiation Monitors As Required by Technical Specification The inspector reviewed the corrective actions take All Instrumentation Department RMS calibration procedures now require a source check be performed during the return to service of its associated procedure This check provides a positive indication of the channels ability to detect radiatio Radioactive checA sources are utilized for all but four channels; containment radiation recorder RMS channels 165, 166, 265, 266 are electronic source checks. In addition, the standing orders existing for grab samples on the air ejection radiation monitors have been replaced by a chaage to TS on December 12, 1988.
, (Closed) Violation 339/87-36-04, Overloading the 2J EDG During
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Testing. The inspector verified the corrective actions taken by the
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licensee. Periodic Test Procedures 2-PT-83.4 and 1-PT-83.4 have been revised to incorporate the correct correlation for voltage to load and to require using all available indications to verify proper EDG loading.
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26 ' Closed) Violation 339/87-36-05,' Violation of TS 6.8.3.B', Changing The Intent of A Surveillance Procedure Without Prior Safety Committee Approval. The inspector reviewed the corrective actions taken by the licensee and verified their implementatio Periodic Test 1/2-PT-212.6, approved on November 19, 1987, has been changed to '
i ensure that reactor coolant system pressure is greater than the accumulator pressure during the performance of the tes NRC Inspection Report 338,339/88-21 closed out related LER 339/87-14 and included additional verification of the licensee's corrective actions. The inspector has no further concern (Closed) Violation 338/87-38-01, Failure to Follow RWP 87-3156. The inspector reviewed the licensee's corrective actions taken as listed in the violation response and agreed that adequate corrective actions l l
have been taken to prevent recurrence of the even An RWP Compliance Memorandum was distributed to each department on January 4, 1988, which called for an RWP Compliance Action Plan to be submitted from each supporting department. ADM 20.19, Adherence To The tadiation Protection Plan, was incorporated into the developed action plans. The inspector reviewed the submitted Action Plans'and has no further concerns at this tim (Closed) URI 339/87-38-03, Lack of Overpressure Protection For The B Accumulato The licensee performed an evaluation of the acceptability of a relief valve downstream of a blocked open (locked)
isolation valve. The subject safety injection accumulator was built in accordance with ASME Section II Class C requirements. Pressure relieving requirements are covered in the ASME Code, Subsection NC, Article 700 Article NC-7142 requires stop valves to have verifiable controls and interlocks to ensure relieving capacity requirements are met under all condition In this case, these controls and interlocks were provided by the administratively locked open vent valve with the key maintained by the shift supervisor. The inspector concurs with the licensee's position that the present relieving arrangement on the accumulator tank is acceptable and within the bounds provided in the ASME Code. This unresolved item is considered close (Closed) LIV 338,339/87-19-18, Mode Change Without Automatic Initiation Available For Auxiliary Feedwater Pump NRC Inspection Report 338,339/87-19 documented four examples which indicated a potential problem with lack of sensitivity to changing modes without fully ope ra-tional TS related equipmen The safety significance {
appears to be minor for each example and two were identified and reported by the license Corrective actions taken by the licensee to address the root cause included issuing 1/2-MISC-35.0, CR0 Turnover Checklist (Modes 1-4) and 1/2 MISC-35.1, CR0 Turnover Checklist (Modes 5-6). The inspector reviewed the turnover checklists and agreed thct they should aid in verifying Auxiliary Feedwater System operability prior to change of mode. In addition, the licensee incorporated changes to operating procedure OP-1.4 for ,
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both unite, which now require independent verification that each'
auxiliary feedwater pump control switch is in auto prior to entering mode (Closed) IFI 338,339/87-34-01, Verification of the Completion of the Repairs to The Unit 2 BBC Browr. Boveri Breakers Per the 10 CFR Part
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21_ Repor The closecut on Unit 2 breakers was delayed due to a
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shortage of the necessary repair and enhancement mate ri al s.. The inspector verified the completion of the repairs by reviewing the associated work orders and interviewing the Electrical' Supervisor in charge of the Unit 2 BBC Brown Boveri breaker No damage to the breakers was found during the breaker . enhancement / repair. This item is considered close , Organizational Changes Effective March 7,, VEPC0 instituted an interim corporate reorganizatio This organization change was made to insure that the licensee could deal more effectively with nuclear problems. The changes realigned the Senior Vice President of Power Operations and Vice President of Power Engineering Services to that of the nuclear program only, separating the non-nuclear responsibilitie The change also created two new positions, Vice President of Nuclear Services in charge of corporate nuclear support functions and Assistant Vice President of Nuclear Operations to assist the present Vice President of Nuclear Operation . Exit The inspection scope and findings were summarized on March 20, 1989, with those persons indicated in paragraph The inspectors described the areas inspected and discussed in detail the inspection results listed below. The licensee did not identify as proprietary any of the material provided to or reviewed by the ir;spectors during this inspectio Dissenting comments were not received from the license (0 pen) Violation 339/89-03-01,' Failure to follow operating procedure 1-0P-49.1A requiring valve 2-SW-242 to be in the closed position (paragraph 5).
(Open) Violation 338/89-03-02, Failure to take adequate corrective action to determine the root cause for the failure of the condenser air ejector radiation monitor due to moisture (paragraph 8).
(0 pen) Unresolved Item 338,339/89-03-03, NRC review of TS 4.6.1. l I
(paragraph 5).
(0 pen) Inspector Followup Item 338,339/89-03-04, Verify adequate service water flow through the recirculation spray heat eschangers (paragraph 4).
(Open) Inspector Followup Item 339/89-03-05, Determine cause for failure of 2-CH-2115E to close and cause for the reset sticking of relay K-604 f
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i during safety ' in'spectim functional test and take corrective action (paragraph 4).
. (0 pen)' Inspector Followup . Item 338,339/89-03-06, Correct CAD system drawings and eliminate' the need for uncontrolled composite drawings (paragraph 7).
(0 pen) Inspector Followup Item 338,339/89-03-07, Review changes to station drawing update program and method for verifying accuracy of drawings (paragraph 10).
16. Acronyms and Initialisms AP Abnormal Procedure AFW Auxiliary Feedwater CAD Computer Assisted Drawing CAE Condenser Air Ejector '
CDA Containment Depressurization Actuation CR0 -Control Room Operator DCP Design Change Package DHR Decay Heat Removal DUR Drawing Update Request EDG Emergency Diesel Generator EP Emergency Procedure ESF Engineered Safety Feature EWR Engineering Work Requests GPM Gallons Per Minute HP Health Physics IFI Inspector Follow-up Item LC0 Limiting Condition for Operation LER Licensee Event Report MCC Motor Control Center MOV Motor Operated Valve MPC Maximum Permissible Concentration MREM Millirem -
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MSSV Main Steam Safety Valve NRC Nuclear Regulatory Commission NSE Nuclear Safety Er.gineering PDTT Primary Drain Transfer Tank PES Plant Engineering Services PORV Power Operated Relief Valve PROM Programmable Read Only Memory PSIG Pounds.Per Square Inch Gauge PTSS Periodic Test Scheduling System RCS Reactor Coolant System RHR Residual Heat Removal RMS Radiation Monitoring System RSHX Recirculation Spray Heat Exchanger RTD Resistance Temperature Detector RWP Radiation Work Permit
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SALP Systematic Assessment of Licensee Performance SI Safety Injection SNSOC Station Nuclear Safety and Operating Committee STA Shift Technical Advisor SW Service Water
, TS Technical Specification 1 l TSC Technical Support Center l UE Unusual Event URI Unresolved Item UFSAR Updated Final Safety Analysis Report VCT Volume Control Tank WOG Westinghouse Owners Group
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.ii APPENDICES TO NRC INSPECTION REPORT 50-338,339/89-03
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APPENDIX 1
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3-2-89 NORTH ANNA POWER STATION UNIT 1 REACTOR TRIP AND TUBE LEAK - 2/25/89 SEQUENCE OF avm.a6 N JY 0800 -
UNIT 1 AT 76% POWER, 725 MW IN COASTDOW UNIT 2 IN MODE PT-46.3A DETERMINATIONPRIMARY TO SECONDARY LEAK RATE RECORDED N-16 RADIATION MONITOR LEAK RATES OF LESS,THAN 1 GPD "A" GPD "B" STEAM GENERATOR LESS STEAM GENERATOR, 2.39 THAN 1 GPD "C" STEAM GENERATOR AND LESS THAh 1 GPD MAIN STEAM HEADER. .
PRIMARY T6 SECONDARY LEAKAGE BASED ON THE AIR EJECTOR RADIATION MONITOR.WAS 0.59 GP :49 -
1-FW-FCV-1498 FAILED IN THE AIR CICSE SUPPLY bUE TO THE FAILURE OF A FITTING"C" MAI LIN :16 -
REACTOR TRIP ON "C" STEAM GENERATOR IDW LEVEL i I
WITH STEAM FLOW GREATER THAN FEEDWATER FIDW MISMATC I INJECTIO ENTERED 1-EP-0, REACTOR TRIP OR SAFETY 1407:18 -
CONTROL TRIP WI'iHROOM MANUALOPERATOR REACTORBACKED TRIP.UP AUTOMATIC REACTOR PUMPS RECEIVED GENERATOR AUTOMATIC BLOWDOWN ISOLATE START SAUXILIARY ON "CjGNAL AND STEAli FEEDWATER I4W-IDW LEVE STEAM GENERATOR 1407:23 -
"B" STEAM GENERATOR IDW-LOW LEVE :24 -
"A" STEAM GENERATOR IDW-I4W LEVE ENTERED 1-ES-0.1, REACTOR TRIP RESPONS MAIN SYSTEM STEAM LINE RADIATION ALARM RECEIVED BY THE SPDS AND CLEARE SUBSEQUENT TO THE SPDS ALARM (UNABLE TO ESTABLISH THE EXACT TIME) A CONTROL BOARD MAIN STEAM LINE RADIATION ALERT ALARM WAS RECEIVED, ACKNOWLEDGED AND CLEARE THE U1 SRO CHECKED ALL MAIN STEAM LINE RADIATION MONITORS AND NORMAL INDICATIONS WERE NOTED ON ALL STEAM LINE SECURED AUXILIARY FEEDWATER FIDW TO ALL STEAM GENERATOR (AUXILIARY FEEDWATER PUMPS RUNNING ON RECIRC.)
MAIN STEAM GENERATORS FEEDWATER PUMP BEING FED USING THE
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LETDOWN ISOLATED AUTOMATICALL "B" STEAM GENERATOR IDW-LOW LEVEL CLEARE LETDOWN RESTORE CONTROL ROOM OPERATOR NOTICED THAT RCS PRESSURE WAS NOT INCREASING AS FAST AS EXPECTED AND MORE CHARGING FLOW THAN EXPECTED WAS NEEDED TO RESTORE PRESSURIZER LEVEL. ONE CHARGING PU RESTORE PRESSURIZER LEVEL TO 20%. MP SUFFICIENT TO 1425 -
SOURCE RANGE NEUTRON DETECTORS MANUALLY RE-INSTATED ,
DUE TO UNDER COMPENSATION OF INTERMEDIATE RANGE DETECTOR i INSTATE N-32 FAILED TO INDICATE WHEN RE- ~
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AIR' EJECTOR RADIATION MONITOR ALARMS HI AND HI-H INDICATION WAS SWINGING ERRATICALLY. 1-AP- UNIT 1 RADIATIO'i MONITORING SYSTEM ENTERED. 8FALTH PHYSICS IS DIRFCTED TO SAMPLE AIR kJECTOR EXHAUS . CHEMISTRY IS D; AECTED TO SAMPLE STEAM GENERATOP BIDWDOW THE SHIFT TECHNICAL ADVISOR CHECKED OTHER RADIATION MONITORS FOR INDICATIONS OF PRIMARY TO SECONDARY LEAKAG BIDWDOWN RADIATION MONITORS DID NOT INDICATE AN INCREASE IN ACTIVITY SINCE BIDWDOWN WAS ISOLATED. N-16 RADIATION MONITORS DID NOT INDICATE AN INCREASE IN ACTIVITY SINCE THE REACTOR HAD TRIPPED. THE "C" MAIN STEAM LINE RADIATION i
MONITOR SHOWED A SLIGHT INCREASE IN ACTIVITY.
I IINDICATED APPROXIMATELY 0.15 HR NORMAL INDICATION APPROXIMATELY 0.04 HR,
. "A" AND."B" MAIN STEAMLINES INDICATED O.02 HR '. ) '
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THE AIR EJECTOR DISCHARGE WAS VERIFIED TO SWAP TO CONTAINMENT ON THE HI-HI RADIATION AIARM. WHEN THE-HI RADIATION AIARM CLEARED THE RADIATION MONITOR HI-HI ALARM WAS RESS.;T AND tHE AIR EJECTOR DISCHARGE
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SWAPPED BAC." TO THE ATMOSPHER (THIS SEQUENCE OF ACTIONS WAS REPEATED NUMEROUS TIMES UNTIL THE AIR EJECTOR DISCHARGE WAS MANUALLY DIVERTED TO CONTAIN-MENT AT 1511. THE TIME THE AIR EJECTOR WAS DISCHARGING TO THE ATMOSPHERE IS ESTIMATED TO HAVR~
BEEN LESS THAN TEN MINUTES.)
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1-AP-24.1 LARGE STEAM GENERATOR TUBE LEAK REQUIRING IMMEDIATE,AND RAPID UNIT SHUTDOWN, WAS' CONSULTE ' -
PRIMARY SYSTEM RESPONSE INDICATED A IDSS OF INVENTORY OF APPROXIMATELY 50 GPM. SUSPECTED "C" STEAM GENERATOR AS THE CAUSE OF LEAKAGE BASED ON THE AIR EJECTOR RADIATION MONITOR AND "C" MAIN STEAM LINE RADIATION MONITOR INDICATIONS. THE "C" STEAM CENERATOR LEVEL TREND DID NOT SUPPORT A POSITIVE DIAGNOSIS AT THIS TIME. AN INCREASE IN CONTAINMENT PUMPING FREQUENCY WAS ALSO'NOTE "C" STEAM GENERATOR LOW-IDW LEVEL CLEARE AIR EJECTOR RADIATION MONITOR EXHAUST SAMPLING HINDERED BY WATER IN LINES. WATER IN LINES CAUSED THE ERRATIC AIR EJECTOR RADIATION MONITOR INDICATION NOTICED TV-BD-100F "C" STEAM GENERATOR OUTSIDE CONTAINMENT ISOLATION VALVE WAS OPEN. IT SHOULD
'9 AVE BEEN CICSED.- VALVE COULD NOT BE CIDSED hANUALLY . TV-BD-100E "C" STEAM GENERATOR INSIDE CONTAINMENT ISOLATION, VALVE, WAS VERIFIED CIASE "A" STEAM GENERATOR IDW-IDW LEVEL CLEARE STEAM DRIVEN AUXILIARY FEEDWATER PUMP SECURE (1-MS-TV-111A & B CLOSED.)
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MAIN FEEDNATER REGULATING VALVE MANUAL ISOLATION VALVES CLOSE BI4WDOWN TRIP VALVES OPENED SAMPLING COMMENCE (BIDWDOWN FLOW TO THE BLOWD6WN TANK HAD BEEN MANUALLY ISOLATED. )
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BIDWDOWN RADIATION MONITORS RETURNED TO SERVIC LETDOWN-FLOW REDUCED BY PLACING A I4WER CAPACITY FI4W ORIFICE IN SERVICE TO DECREASE CHARGING FID _ _ _ _ - _ _ - - _ - - _ - -
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"A" AND "B" AUXILIARY FEEDWATER PUMPS SECURED'AND RETURNED TO-AUTOMATI '
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HIGH RADIATION ALARM RECEIVED AND IOCKED IN ON RM-RMS-160 CONTAINMENT GLJEOUS RADIATION MONITO AP-5.1 kNTERE CI4 SED "C" 7EEDWATER REGULATING VALVE BYPASS VALVE AND ITS MANUAL ISOLATION VALV HIGH RADIATION ALARM RECEIVED AND CLEARED ON RM-VG-103, "A" STACK RADIATION MONITO "C" STEAM GENERATOR LEVEL TREND WAS CONSTAN ' CONTROL ROOM RECEIVED INFORMATION THAT PERSONNEL IN AUXILIARY BUILDING WERE BEING DELAYED IN EXITING DUE TO SLIGHT GASEOUS CONTAMINATIO EXTENSIVE WALKDOWN OF THE AUXILIARY' BUILDING WAS COMMENCE AUXILIARY BUILDING PARAMETERS HAD BEEN MONITORED AND DID NOT SHOW SIGNS OF A LEA "C" STEAM GENERATOR BI4WDOWN RADIATION MONITOR HIGH/HIGH ALARM RECEIVED. AP 5.1 ENTERE LETDOWN WAS SECURED IN AN ATTEMPT TO ISOLATE POSSIBLE LEAK PATH "C" STEAM GENERATOR LEVEL OBSERVED TO BE DECREASIN CONTROL ROOM RECEIVED INFORMATION THAT PERSONNEL EXITING THE SECURITY BUILDING WERE BEING DELAYED IN EXITING DUE TO SLIGHT GASEOUS CONTAMINATIO AIR EJECTOR DISCHARGE MANUALLY DIVERTED TO CONTAIN-MENT DUE TG CONTINUED ERRATIC INDICATIO COMMENCED EMERGENCY BORATION IN ACCORDANCE WITH 1-AP-2 i 1517 -
1-MS-95 'C' GTEAM GENERATOR STEAM SUPPLY TO THE STEAM DitIVEN AUXILIARY FEEDWATER PUMP; WAS MANUALLY ISOLATED 1520 -
CHEMISTRY REPORTED "C" STEAM GENERATOR BLOWDOWN SAMPLE SHOWS HIGH ACTIVITY. "C" STEAM GENERATOR POSITIVELY IDENTIFIED AS THE SOURCE OF LEAKAG EPIP-1.01, EMERGENCY * MANAGER CONTROLLING PROCEDURE, -
ENTERED 1521 -
HEALTH PHYSICS REPORTS CONTACT READING FROM THE "C" MAIN STEAM TRIP VALVE OF 5 MR/H READING THE DAY BEFORE WAS 0.02 MR/H LEAKAGE ESTIMATED TO BE APPROXIMATELY 65 GP STATION EMERGENCY MANAGER DECIARED AN ALERT BASED ON A REACTOR COOLANT SYSTEM L$ed OF GREATER THAN 50 GPM. EPIPS(THIS WASANA ALERT REQUIRE CONSERVATIVE ACTION TO BE DECLARED BECAUSE WHEN THE REACTOR n
COOLANT SYSTEM LEAKAGE IS GREATER THAN 50 GPM MD MORE THAN ONE (1) CHARGING PUMP IS NEEDED TO MAINTAIN PRESSURIZER LEVEL.)
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REACTOR COOLANT SYSTEM COOLDOWN COMMENCED IN ACCORDANCE WITH 1-AP-2 CHARGING PUMP SUCTION MANUALLY SWAPPED TO RWST FROM VC _ - _ _ _ _ _ _ - - _ _ _
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WITH REACTOR COOLANT TEMPERATURE AT APPROXIMATELY 520 DEGREES F THE SHIFT SUPERVISOR EVALUATED THE EFFECTS OF CO6 LING DOWN WITH TH3 "C" STEAM
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GENERATOR OPE MAIN STEAM TRIP VALVE (1-MS-TV-101C).
DECISION WAS MADE TO CLO3E THE VALVE AND CONTINUE TO COOL DOW '
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' STARTED'A SECOND CHARGING PUMP TO KEEP UP WITH INVENTORY REDUCTION DUE TO COOLDOW GREG KANE ASSUMES POSITION OF STATION EMERGENCY MANAGE >!; 1600 -
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STARTED AUX FEEDWATER PUMPS ON RECIRCULATION IN THE i ANTICIPATION OF LOSS OF MAIN FEEDWATER ("C" STEAM GENERATOR LEVEL AT 72%).
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"C" STEAM GENERATOR LEVEL STARTED TO SIDWLY DECREASE
.AS PRESSURE IN THE REACTOR COOLANT SYSTEM WAS REDUCED TO BELOW STEAM GENERATOR PRESSUR TECHNICAL SUPPORT CENTER (TSC) FULLY MANNED.
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ENTERED 1-ES-3.1, POST-SGTR COOLDOWN USING BACKFIL SECURED SECOND CHARGING PUM THE PUMP WAS NO LONGER NEEDED TO MAINTAIN PRESSURIZER LEVE LETDOWN RESTORE STATION EMERGENCY MANAGER RELOCATED TO TSC AND TSC IS DECLARED OPERATIONA ,
1619 --
SECURED EMERGENCY BORATIO ' SECURED AUXILIARY FEEDWATER PUMP ' -
UNIT ENTERED MODE PLACED RHR SYSTEM IN SERVIC UNIT ENTERED MODE ALERT TERMINATE .
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APPENDIX 2
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MEMORANDUM To T. L. Porter )
Nuclear Safety Engineering FROM J. J. Mosher February 28, 1989 ESTIMATION OF RCS TEAKAGE FROM UNIT ONE "C" STEaN GENERATOR Based on GETARS gra after the reactor trip, phrateofofPressurizer decrease was level fifteen minutes approximately 1%
every 2 minute j 1% Pressurizer level = 46 Gallons; therefore, the rate of
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Pressurizer level decrease was approximately 23 gy Based on SPDS graphs of Charging and Letdown flows, fifteen minutes after the trip, Letdown flow was ninety ei (98) gpm-and Charging flow was one hundred twenty eight (128)ght gy !
Based on P-250 alarm typewriter printout, #1 RCP Seal Leak-off strip chart recorder and observation, . Seal Injection flows fifteen minutes after the trip were ten (10) wm and #1 Seal
. Leak-off flows were approximately two (2) gym. This resulted in approximately twenty four (24) gpm flow into the RC PT-52.2A, Reactor Coolant System Leakrate, was performed on 2-22-89 at 2120 hour0.0245 days <br />0.589 hours <br />0.00351 weeks <br />8.0666e-4 months <br /> Identified Leakage was 3.10 gpm and Unidentified Leakage was 0.47 gpa. A conservative estimate of RCS leakage for this calculation is three (3) gy CONSERVATIVE ESTIMATE OF "C" S/G TUBE LEAK:
LEAK FLOW = CHARGING FLOW + NET M/U FIOW FROM SEAL INJECTION
- RCS LETDOWN FLOW + PRESSURIZER LEVEL DECREASE
- KNOWN RCS LEAKAGE
= 128 gpa + 24 gpm - 98 gpm + 23 gpa - 3 gpm I
= 74.gna
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J. J. Mosher
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