IR 05000338/1989026
| ML20248B518 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 09/21/1989 |
| From: | Caldwell J, Fredrickson P, King L, Munro J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20248B477 | List: |
| References | |
| 50-338-89-26, 50-339-89-26, NUDOCS 8910030223 | |
| Download: ML20248B518 (21) | |
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REGION 11
Ij 101 MARIETTA STREET.N.W.
- ATLANTA, GEORGI A 30323
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Report Nos.:
50-338/89-026 and 50-339/89-026 Licensee:
Virginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.: 50-338 and 50-339 License Nos. :
NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: July 15 - A gust 22, 1989 Inspectors:
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E L. Caldwell, Senior Resident Inspector Date Signed YA fr fd N
LT P~. King, Resident I'nspector Date Signed Wh WA Fw 1/21/21 J. F. Munro, Resident Inipector Date Signed Accompanying Per nel:
J. E. Beall
)S.M.Shaeffer Approved by:
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P. E. Fredrickson, Section Chief Date Signed Division of Reactor Projects SUMMARY Scope:
This routine inspection by the resident inspectors involved the following areas:
plant status, maintenance, surveillance, engineered safety feature walkdown, operational safety verification, operating reactor events, licensee event report followup, licensee action on previous enforcement matters, plant startup from refueling, and design changes and modifications. During the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshift operations on the following days : July 15, 16, 17, 18, 19, 27, 31, August 3, 6 and 19, 1989.
Results:
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Within the areas inspected, one violation with three examples, was identified for failure to have adequate surveillance procedures to perform engineered safety feature slave relay testing (paragraph 4). Three unresolved items were also identified, involving cable separation problems (paragraph 6), pressurizer heater breaker problems (paragraph 6), and a 10 CFR 50.59 review concerning the Unit 2 turbine mechanical overspeed test (paragraph 9).
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Mf4 UNITED STATES
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101 MARIETTA STREET, N.W.
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ATLANTA, GEORGI A 30323
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Report Nos.:
50-338/89-026 and 50-339/89-026 Licensee:
Virginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.: 50-338 and 50-339 License Nos.:
NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: July 15 - A gust 22, 1989 C
d U/87 Inspectors:
E L., Caldwell, Senior Resident Inspector Date Signed A
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LT P. King, Resident I'nspector Date Signed
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/M 7/2//e1 J. F.
iunro, Resident Inipector Date Signed J. E. Beall
)nel: jS.M.Shaeffer Accompanying Per Approved by:
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P. E. Fredrickson, Section Chief Date Signed Division of Reactor Projects
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SUMMARY Scope:
This routine inspection by the resident inspectors involved the following areas:
plant status, maintenance, surveillance, engineered safety feature walkdown, operational safety verification, operating reactor events, licensee event report followup, licensee action on previous enforcement matters, plant startup from refueling, and design changes and modifications. During the performance of this inspection, the resident inspectors conducted reviews of
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the licensee's backshift operations on the following days : July 15, 16, 17, i
18, 19, 27, 31, August 3, 6 and 19, 1989.
Results:
Within the areas inspected, one violation with three examples, was identified for failure to have adequate surveillance procedures to perform engineered
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i safety feature slave relay testing (paragraph 4). Three unresolved items were also identified, involving cable separation problems (paragraph 6), pressurizer heater breaker problems (paragraph 6), and a 10 CFR 50.59 review concerning the Unit 2 turbine mechanical overspeed test (paragraph 9).
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The inspector also expressed concern to station management regarding the availability of acceptance criteria in alarm response procedures, the lack i
of active engineering involvement in reviewing data that may affect the performance of safety-related equipment, and the use of portable fans 'to maintain the operation of equipment needed following an accident (paragraph 6).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees M. Bowling, Assistant Station Manager G. Clark, Supervisor Quality
J. Downs, Superintendent, Administrative Services R. Driscoll, Quality Control. Manager R. Enfinger, Assistant Station Manager
G. Gordon, Electrical Supervisor G. Flowers, Configuration Management Supervisor R. Irwin, Supervisor Health Physics
D. Heacock, Superintendent, Engineering
G. Kane, Station Manager-
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J. Leberstein, Engineer.
- W. Matthews', Superintendent, Maintenance T. Porter, NSE Supervisor D. Quarz, Engineer
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C. Snow, Acting Superintendent, Technical Services
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 personnel.
NRC management site visit: On July 20, 1989, Commissioner K. Rogers and Technical-Assistant Dr. G. Mar;us visited the North Anna Power Station for a tour of the station and a discussion with licensee site management on matters of mutual interest.
Attended exit interview-
Acronyms and initialisms used throughout this report are listed in the last paragraph.
2.
Plant Status On July 15, the beginning of the inspection period, Unit I was in Mode 3 with a plant heat-up and pressurization ongoing in preparation for a reactor startup.
The reactor startup commenced with criticality being achieved on July 15.
On July 16, Mode 1 was entered and the turbine generator was placed on line.
On July 19, the unit experienced an automatic reactor trip from 90% power.
The trip was initiated by a turbine trip that resulted from a failed 0-ring on the trip solenoid valve, SOV 20-ET, venting EHC pressure to less than that required to hold open the trip throttle valves. A four-hour report was made in accordance
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with 10.CFR 50.72 (see paragraph 7 for details). On July 20, the reactor
was restarted and the turbine generator placed on line. The unit achieved 100% power on. July 24.. A one-hour report was made. on August 14 i n -
accordance:with 10 CFR 50.72-(b) (ii) (B) due to an error discovered in the current. large break LOCA ' analysis for-the 18% SG tube plugging licensing. case (see-paragraph 7 for details).
The inspection period concluded on August 22 with the unit at 100% power and on line for 35 days of continuous operation.
On July 15, the beginning of the inspection period, Unit 2 was operating at 100% pcwer, day 69 of continuous on-line operation. On August 6, an unexpected closure of the casing cooling supply valve to recirculation
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spray, 2-RS-MOV-2018, occurred during SSPS slave. relay testing.
A four-hour report was made on August 8 in accordance with 10 CFR 50.72.
The event was subsequently reclassified and a one-hour report made -on.
August 21'(see paragraph 4 for details). The inspection period concluded on August 22 with the unit at 100% power and on line for 107 days of continuous operation.
3.
Maintenance (62703)
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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 TS.
On August 3,1989, the inspector observed replacement.of the mechanical seal package on the Unit 1 quench spray recirculation pump 1-QS-P-2A. The recirculation pumps have been a constant source of gland leakage and the seal package had been replaced several times before. This time however, it was thought that the axial movement of the pump was damaging the seal package, therefore, the motor thrust was shimmed to prevent recurrence.
The pump is a two speed pump and it is believed the problem with the seals
.is caused when the pump speed is changed and axial movement occurs.
Procedure MMP-C-GP-1, Inspection and Repair of Safety Related Pumps in General, was used.
No problems were identified.
On August 4,1989, the inspector observed work on the Unit 2 hydrogen analyzer for post accident monitoring.
Procedure -IMP-C-1-MISC-02, Troubleshooting Replacement and Repair of Failed Parts for the H2-Analyzer, was used.
This work was. performed as part of a seven year replacement program, and included the installation of auxiliary contacts, an overload heater, a motor starter and breaker.
No problems were identified.
4.
Surveillance (61726)
The inspectors observed / reviewed TS required testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, tbt LCOs were met and that any deficiencies identified were properly reviewed and resolved.
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The inspector witnessed the performance of the following tests on the specified dates:
a.
Quench Spray System - A Subsystem,1-PT-63.1A on August 2.
b.
Valve-Inservice Inspection, 2-PT-213.8 on August 2 (Train A only),
c.
2H Diesel Generator Test (start by ESF Actuation), 2-PT-82.4A on August 3.
d.
AFW Pump (2-FW-P-2) and Valve Test, 2-PT-71.1 on August 4.
The tests were satisfactorily conducted in accordance with the procedures.
The test data was subsequently reviewed and met the acceptance criteria.
On August 6, the inspector witnessed 2-PT-36.5.3A and 3B, SSPS Output Slave Relay Test on Trains A and B.
The tests were satisfactorily completed.
The test of' the K614 relay was satisfactorily completed on August 8.
These tests were the first attempt by the licensee to test certain SSPS output slave relays with the unit on line.
Three problems, resulting from procedural inadequacies, were encountered during testing.
c.
The K630 relay failed to energize on the first attempt.
The procedure incorrectly indicated that the LHSI pump discharge MOV was required to be closed in order to pick up K630. Subsequent licensee review indicated that the LHSI pump suction valve ( MOV-2862A ), and not the discharge valve, was required to be closed to satisfy the interlock necessary to energize K630.
A procedure deviation was processed and the relay satisfactorily tested.
This is the first example of violation 339/89-26-01 for an inadequate procedure.
b.
The procedure for testing relays K645 and K645XA did not indicate that valve 2-RS-MOV-201B, casing cooling supply to recirculation spray, _ would close as a result of auxiliary relay interlock 3G-2SWEA03 energizing with existing system conditions.
The unexpected valve actuation was identified by the operator 55 minutes after initially energizing the K645 and K645XA relays. This is the second example of violation 339/89-26-01 for an inadequate procedure.
A procedure deviation was processed to properly address this inter-lock prior to the performance of testing on Train B.
For 22 minutes of this time, the breaker for the inside recirculation spray pump, 2-RS-P-1A, was in the test position per the procedure in effect.
Thus, the licensee had inadvertently and unknowingly niet the conditions for entry into TS 3.0.3 for 22 minutes, with one contain-ment recirculation spray subsystem and one casing cooling subsystem j
The licensee's July 12, 1989 submittal to the NRC regarding ESF testing indicated an interlock on the analogous MOV on Unit I following energization of the 3G-2SWEA03 auxiliary relay.
In addition, the licensee's review of the valve logic diagrams following the test indicated that actuation of 2-RS-MOV-201B was proper.
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The: licensee-evaluated the unexpected valve actuation for deportability in accordance with 10 CFR 50.72 (b)(2)(ii).
Initisl SNSOC review determined that the event was not reportable based largely on the understanding of the intent of Precaution 4.4 of the procedure in progress, i.e. "During performance of this procedure, if circuitry in the Safeguards Test Cabinet fails, the applicable-engineered safety features actuation will occur and shall be anticipated."
The event was subsequently reported as a four-hour report on August 8 following inspector discussions with the licensee and confirmation that the actuated valve was an ESF component. On August 21, following further evaluation, the licensee reclassified the event and made a one-hour report in accordance with 10 CFR 50.72 (b)(ii) and 50.72 (b)(ii)(B). This evaluation indicated that valve 2-RS-MOV-201B 'was powered from the 2H emergency bus but was a component in the B train of the casing cooling subsystem with equipment powered from the 2J emergency bus.
c.
One relay (K614) was tested on August 8.
The plant conditions for testing this relay could not be established on August 6.
During the test, valve TV-SV-202-1, SJAE Discharge to Containment, could not be opened. A work request was initiated with subsequent investigation indicating an obstruction in the air supply line.
The obstruction was cleared and air regulator replaced. The inspector discussed the work repairs with the cognizant mechanic. The mechanic indicated that a-solid particle had apparently lodged in the 1/4" instrument-air piping upstream of the air regulator and its isolation valve. He further indicated that there was an absence of any water or oil contamination in the air flow.
The K614 relay was satisfactorily tested on August 8 following these repairs.
A third procedural inadequacy was identified by the licensee on August 8 after completion of the above test.
This is the third example of violation 338,339/89-26-01. During testing of RM-SV-221, radiation monitor for air ejector discharge to containment, valves TV-SV-202-1 and 203 did not open on a Hi-Hi radiation signal.
These valves would not have opened if an actual signal had been received.
This condition was in effect for approximately five hours.
Investigation revealed that the Phase A signal generated as a result of testing the K614 relay (2-PT-36.5.3A & 3B) had not been reset.
The Phase A signal was reset and the valves returned to proper operation.
5.
ESF System Walkdown (71710)
The Unit 1 auxiliary feedwater system was verified operable by performing a walkdown of the accessible and essential portions of the system on August 3,1989, using procedure 1-0P-31.2A, Valve Checkoff - Auxiliary Feedwater. The following observations were noted:
a.
Valve 1-FW-194 was observed to be open, as required by the valve checkoff procedure. However the applicable drawing showed the valve
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to be. closed.
This valve is a sample valve that was isolated downstream, and therefore, of minor safety significance.
The licensee subsequently closed the valve and informed the inspector that the procedure would be changed to be consistent with the drawing.
b.
Valve 1-FW-187, the outlet isolation valve for the 1-FW-P-3B
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auxiliary feedwater pump recirculation restricting orifice, was observed to be in a throttled position as required by the procedure.
In light of the recent findings that minimal recirculation flow was contributing to long term degradation of the pumps, the inspector requested the licensee to determine the reason for the throttled position.
c.
The inspector observed three apparently newly installed valves, one on each of the pump's casings. These valves were. not listed in the valve checkoff procedure.
A review of the control room drawings showed that these valves, 1-FW-531,532.and 533, had been added. The licensee was requested to determine which procedure installed these new valves and why the valve checkoff procedure had not been updated.
Each of the above observations was discussed with the licensee.
The requested licensee actions will be identified as inspector followup item 338/89-26-05.
Within this area, no violations or deviations were identified.
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 conditions.
Through log review and plant tours, the inspectors verified compliance with selected TSs and LCOs.
In the course of the monthly activities, the 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; and badge issuance and retrieval. On a regular basis, RWPs were reviewed and the specific work activity was monitored to assure that the activities were being conducted per the RWPs.
The inspectors kept informed, on a daily basis, of overall status of both units and of any significant safety matter related to plant operations.
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 daily.
The inspectors conducted various plant tours and made frequent visits to the control room. Observations
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g included: witnessing work activities in progress; verifying the status of operating and standby safety systems and equipment; confirming valve positions, instrument and recorder readings, and annunciator alarms; and observing housekeeping.
On August 14, a one-hour report was made to the NRC in accordance with 10 CFR 50.72 (b)(ii)(B) due to an error discovered in the current large break LOCA analysis for the 18% SG tube plugging licensing case.
An incorrect enthalpy was used for the water in the pressurizer, which resulted in an increase in the core reflood rate. This input error was discovered by the licensee on August 8 during the running of the T(hot)
reduction large break LOCA case.
The impact of this error was subsequently determined by rerunning the licensing case with the correct input. On August 12, it was determined that the resulting PCT would be greater than the original analysis PCT, and also greater than the 2200 degrees F, 10 CFR 50.46 limit.
Both North Anna units are covered by the same large break LOCA analysis, which uses an assumed SG plugging level of 18%.
The worst case SG plugging for the present operating conditions is' less than 14% for Unit 1 and 6% for Unit 2.
Because previous analyses did not include the recently discovered input error these previous analyses can be used to show that Unit 2 would still be below the LOCA limits of 10 CFR 50.46, and therefore restrictions on current operating conditions are not necessary.
However, due to the greater tube plugging levels in Unit 1 and based on the corrected licensing analysis, the licensee determined that temporary operating restrictions were necessary to ensure that the large break LOCA results will remain within applicable limits. The temporary operating restrictions which were imposed on August 14 for Unit I by Standing Order
- 172, are as follows:
1.
RWST Minimum Temperature 42 degrees F 2.
Containment Minimum Temperature 98 degrees F 3.
FQ Limit Maximum 2.15 The above restrictions will reduce the amount of power available in the hot channels and improve the core reflooding rate during accident conditions.
Thus, core cooling is increased and expected PCT reduced.
The analysis was run at the 18% tube plugging case using the above
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restrictions and the PCT was sati sfactory (2184 degrees F).
These restrictions will exist until the licensee can modify and re-analyze the large break LOCA case. The restriction on FQ would change the limit for comparison to the measured core power distribution in TS 3.2.2 from 2.19 to 2.15.
It would not be necessary to change the Axial Flux Difference limits or the N(Z) function curves submitted to the NRC for Unit 1 Cycle 8.
During the week of July 24 through July 28, the inspector conducted a detailed walkdown of the Units' I and 2 quench spray, auxiliary feedwater and safeguards buildings. Also inspected were the emergency switchgear
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rooms, cable vaults and service water structures. The emphasis of the inspection was the installation of electrical cable, material condition of equipment, and plant housekeeping. The level of housekeeping was found to be very good, with active efforts to avoid the spread of contamination and with an aggressive painting program in place. Minor deficiencies, such as untaped cable ends, missing conduit covers and damaged cable tray covers, were identified to the licensee for correction.
With regards to the installation and separation of electrical cable, these activities are controlled by NAS-3012, Criteria Specification for Design and Identification of Electrical Cable Systems.
The specification was found not to contain the guidance presented in the UFSAR (Section 8.3.1.1.2.3) on alternative methods to provide physical separation in cases where distance alone is not available. The UFSAR (especially Figure 8.3-15) allows barriers to be placed between cables, which, with specified overages, substitutes for distance.
The exact construction of the barriers is not contained in the UFSAR, although a commitment to " solid metal tray covers" is made.
Fiberboard sheets made of a fire barrier material were found to be installed in several locations (e.g., emergency switchgear) directly attached to metal tray covers.
In other locations (e.g., safeguards buildings), the board material was used in lieu of metal covers and in some cases was found to be broken. The inspector identified several examples of safety-related cable installation which did not meet the separation criteria in NAS-3012 or the UFSAR.
In particular, in the Unit 2 safeguards building, cable entering tray 2TK036P was found not to have adequate separation from tray 2TLO450 at several locations.
Neutral cable entering tray 2TX109N in between those two trays was also found not to have adequate separation from the safety-related cable. In many other cases, the in-situ geometry did not appear to be represented in the UFSAR and should be evaluated.
The licensee is currently developing an inspection plan to perform walkdowns of other plant areas where high concentrations of trays and conduits exist. These walkdowns will be completed in accordance with the i
current cable separation specification (NAS-3012).
This item will be identified as unresolved item 338,339/89-26-02, pending completion and inspector review of additional licensee walkdowns.
Also during the walkdown, the inspector identified a concern involving the elevated temperatures in the cable vaults, battery rooms, and rod drive rooms, and the extensive use of portable fans and blowers. Sustained high temperatures have the potential to impact personnel performance in those areas, tu cause accelerated aging of equipment, and to allow local hard-to-detect hot spots within energized components such as cabinets, breakers or conduits.
Localized high temperatures may impact equipment operability and cause failures. Portable fans are not permanent, analyzed components and cannot be taken credit for in assuring the operability of equipment important to safety. As a result of these observations the inspector reviewed the backboard operator log,1-LOG-6A, for the logged temperature readings concerning the areas in question.
Several of the areas had temperature readings greater than the acceptance criteria listed
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on the log.
The inspector questioned the assistant shift supervisor concerning the actions required when the temperature exceeded the maximum limit listed in the log. The inspector was informed that actions would be taken'to reduce the temperature, such as increasing the installed ventila-tion or installing temporary ventilation, if possible.
However, the operators were not aware of any requirement to notify engineering of the elevated temperatures nor did engineering review the logs.
Along with the assistant shift supervisor, the inspector also reviewed the annunciator response procedure for the high area ambient temperature alarm and became aware of a requirement for the operators to write a deviation report for any area temperature which exceeded the UFSAR table limits.
Since the UFSAR limits were not listed in the acceptance criteria and the operators did not routinely review the UFSAR, deviation reports were not being written.
Following a discussion with the licensee concerning the problem of acceptance criteria not being readily available to the operators, the licensee changed 1-LOG-6A to include the UFSAR limits and added a statement requiring that a deviation report be written any time the limits are exceeded. Because several of the area temperature limits had been exceeded, deviation reports were written.
As result of the above findings, the inspector raised several areas of concern to station management.
The first involved operator actions required to respond to alarms in which the alarm response procedures does not readily available acceptance criteria. The licensee was requested, during their procedure upgrade process, to ensure that procedures especially the alarm response procedures were changed to be user triendly especially in the area of acceptance criteria. The second area of concern involved the failure of engineering to be actively involved in reviewing data that may potentially affect the performance of safety-related equipment, e.g. the effects on EQ due to elevated temperatures. The use of deviation reports will increase engineering attention to the problem of elevated temperatures.
However the inspector believes engineering should take a more pro-active approach in their efforts to track and trend data relating to equipment operational performance. The final area of concern involves the use of portable fans, which are not powered from emergency power, to maintain operation of equipment that is needed following an accident. The equipment of particular concern are the pressurizer heater breakers, which appear to have a problem with the elevated temperatures.
On several occasions a number of the heater breakers have tripped, apparently due to the high temperatures. The most notable ocasion was the recent Unit I reactor trip where, because of the loss of some of the heaters, pressure was much slower in returning (see paragraph 7 for details). The licensee placed several portable fans in the area of the heater breakers in an attempt to prevent the tripping. The inspector has requested the licensee to perform an engineering analysis to verify the operability of equipment required following an accident, assuming the loss of the temporary ventilation fans.
Pending a review of this analysis, this will be identified as unresolved item 338,339/89-26-03.
Within this area, two unresolved items were identified.
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7.
Operating Reactor Events (93702)
.The inspectors reviewed activities associated with the below listed reactor events.
The review included. determination of cause, safety
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significance, performance of personnel and systems, and corrective action.
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The inspectors examined instrument recordings, computer printouts, operations journal entries, scram reports and had discussions with operations, maintenance and engineering support personnel as appropriate.
On July 19 at 5:40 p.m. Unit 1 experienced a turbine trip / reactor trip from approximately 90% power. The unit had been placed on line on July.16 following the refueling outage and was in the' process of increasing power to 100%. The licensee determined the cause of the turbine trip to be a failed 0-ring on the turbine trip solenoid valve 50V-20-ET, which allowed EHC pressure to reduce to the point where the tr_ip throttle valves went shut.
This generated a turbine trip signal, which also results in a reactor trip signal any time reactor power is greater than 10%.
The licensee has determined the most probable cause of the 0-ring failure to be the result of improper installation.
However a root cause evaluation is still ongoing.
The reactor response to the trip was routine with the exception of reactor pressure, which stabilized lower than usual and was slower to return, and pressurizer level, which had to be maintained with a-second charging pump.
Both RCS pressure and level were maintained above the safety injection setpoint and manual initiation criteria.
The licensee determined the cause of the sluggish pressure response and the need for the second charging pump to be a combination of the lack of decay heat due to the new core, the cold water being fed to the SG from auxiliary feedwater, and the loss: of several (6) pressurizer heaters due to their breakers having tripped. The pressurizer breaker tripping has been attributed to under-rated heater cables combined with elevated ambient temperatures in the rod drive room which houses the heater breakers. The problem with inadequate ventilation in this room has been discussed in an earlier NRC inspection Report (338,339/89-08).
This earlier problem involved the failure of several safety-related 480 volt breakers, due in part to the dust and dirt introduced into the breakers by temporary fans operating in the room with the outside door open.
A violation was issued, and as a result the licensee no longer opens the outside door.
However, the inadequate ventilation pr.oblem in the rod drive room has not been resolved and appears now to have a greater effect on the operability of the pressurizer heater breakers. The concern related to the elevated area temperatures and their effects on the operation of various equipment are identified as an unresolved item in paragraph 6.
The long-term corrective action will involve a redesign of the cable ampacities and permanent installation of air conditioning in the rod drive and cable vault areas. The inspectors will continue to monitor the licensee's corrective actions.
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The operator response to the reactor trip was very good. The inspector entered' the control room just after the trip occurred. At the time the operators had just. exited EP-0, P..ector Trip or Safety Injection, and were entering ES-0.1, Reactor Trip Response.
The inspector observed the operator actions to be very controlled especially the ' procedure reader whose directions were loud, distinct and directed to the responsible
' operator by name. The procedure reader did not proceed until he received the required response from the operators.
Because the trip was not completely routine the inspector was able to observe the operators give negative responses to some of the EP questions which required the response-not-obtained section of the EP to be used.
In each case the l
appropriate actions were taken such as isolating letdown and starting the
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second charging pump when pressurizer level and pressure did not respond as expected.
Within this area, no violations or deviations were identified.
8.
Licensee Event Report Follow-up (90712)
The following LERs were reviewed and closed. The inspector verified that reporting requirements had been met, that causes had been identified, that corrective actions appeared appropriate, that generic applicability had been considered, and that the LER forms were complete. Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or TS conditions had been identified.
-(Closed) LER 338/87-010, Steam Generator Tube Defects Greater Than 1% Of Initial Sample Group Were Defective.
The licensee submitted a supplemental SG tube integrity report dated May 5,
1988.
This supplemental report detailed further nondestructive and destructive examination results of two tubes that were removed from the Unit 1 "A" SG.
Preliminary results of the examinations revealed circumferential stress cor rosion cracking in the expansion transition region at the tube sheet top location and minor outside diameter intergrannular corrosion of both
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tubes. The licensee is utilizing the examination results in the Thermal
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Stress Relief program.
This LER is considered closed.
(Closed) LER 338/87-015, Reactor Trip Due To 5A Feedwater Heater High -
High Level. This LER was previously-addressed in NRC Inspection Report 338,339/89-03. The licensee has completed a Human Performance Evaluation System report, HPE587-122, which recommends applicable procedural changes, operations personnel training, and performance of an instrument air valve lineup procedure. The inspector verified that these recommendations have t
been implemented to prevent recurrence of similar events.
In addition, the licensee has completed the instrument air valve lineup in the Unit I r containment. This LER is considered closed.
(Closed) LER 338/88-013, Turbine Trip / Reactor Trip - EHC System L
Malfunction.
The licensee performed an evaluation to determine whether inspection and maintenance of the turbine control valve actuators, including dump valves, were warranted during the 1989 outages due to the
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As a result of the evaluation, ' both - units'
l control l valve actuators and associated dump valves were tested and l
repaired or replaced according to the results of the test. The inspector
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reviewed and concurs with the licensee's corrective actions.
(Closed) LER 338/88-023, Missed Surveillance on Penetration Fire Barriers.
The inspector. reviewed the licnesee's corectiveiactions and verified that
- the appropriate actions to prevent recurrence were implemented.
The licensee evaluated EWR-87-615 in order to identify all fire dampers protecting safety related and nonsafety-related area. No major concerns were identified; however, numerous drawing problems were observed and l~
subsequently corrected.
'(Closed) LER 338,339/88-028, Diesel Driven Fire Pump Batteries Not Seismic.
The licensee replaced the existing non-seismically qualified batteries on the diesel driven fire pumps with seismically qualified batteries.
The' new batteries were installed and tested satisfactorily within the Action Statement time frame requirements of TS. The inspector reviewed the licensee's. corrective actions, which included a JC0 documenting the capability of the existing battery charger to recharge the new. batteries within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
9.
Plant Startup From Refueling (71711)
On July 15 and 1.6, the inspectors witnessed portions of the Unit I restart following the refueling outage.
The reactor was taken critical at 3:32 p.m.
on July 15, and the unit was placed on line on July 16.
The inspectors observed the.startup to be deliberate and controlled. No major
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perturbations associated with the startup occurred until a reactor trip on July 19 (see paragraph 7 for details).
As was performed prior to. the Unit 2 restart, the licensee conducted a startup assessment prior to the Unit I restart.
Portions of the assessment were reviewed by the inspectors. This assessment involved the superintendents from each department making presentations to the Station Oversite Board regarding accomplishing their responsibilities during the
- ,utage to allow the unit to restart. These presentations provided station management with objective evidence on which to base a restart decision.
The' inspectors believe that these restart assessments are a strength.
Also, based on the successful restart of both units with the exception of the July 19 reactor trip the startup assessment appear to be very effectiv _.
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During the restart of Unit 1, the inspector observed portions of c the following procedures:
1-PT-10.3 Shutdown Margin Calculation 1-PT-94.0 Refueling Nuclear Design Check a.
Step 4.7 All-Rods-Out Boron Endpoint Determination b.
Step 4.9 Reactivity Worth Determination of the Most Reactive Control Bank The inspectors did not identify any problems associated with the portions of the procedures witnessed.
On July 17, following the restart of the unit and the placement of the turbine on the grid, the licensee reduced reactor power to less than 10%
in preparation for the overspeed test of the main turbine. Following the removal of the turbine from the grid, the-licensee conducted 1-PT-34.5, Turbine - Generator Trip Test.
The inspector witnessed the test and observed the main turbine trip at a speed of 1982 RPM. The acceptance criteria war 1940 ' to 1998 RPM; therefore the test was determined to be successful.
This test of the mechanical overspeed function of the turbine was not performed following the Unit 2 restart from the refueling outage. The decision not to perform the test was based on the desire to keep the unit on line and not on a good understanding of the requirements.
Subsequent to the: decision, engineering found a requirement in the UFSAR to perform the test following each refueling and a 10 CFR 50.59 safety evaluation was performed to justify delaying the performance for a grace period similar to the 25% grace period stated in TS. However, engineering also found a commitment made to the ~ ASLB during the licensing process requiring that the mechanical overspeed test be performed each refueling outage.
Consequently, the decision to perform the Unit 1 overspeed test was made.
The Unit 2 mechanical overspeed test still has not been performed. The licensee has prepared a 10 CFR 50.59 safety evaluation allowing a delay in performing the test until the weather conditions allow the grid load requirements to be reduced. This safety evaluation will be reviewed by the Region II staff for adequacy.
Pending the completion of the review, this situation will be identified as an unresolved item (339/89-26-04).
Within these areas, on unresolved item was identified.
10.
Design Changes and Modifications (37700)
On August.17, the inspectors attended a brief conducted by the licensee regarding the current status and plans for the sercice and instrument air system upgrades. The upgrades are aesigned to provide increased system reliability and are a result of the licensee's response to violation 338,339/88-36-01 and the commitments made in response to Generic Letter
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The system modification will entail the replacement of the existing air compressors with two service air compressors and two instrument air compressors. Two new desiccant air dryers, each sized for two unit operation, will be installed in the instrument air system. The service air compressors will be the normal supply of both service air and instrument air to both units. One compressor will normally operate with the other as a backup. The instrument air compressors will be designated for emergency standby operation and.will not normally operate.
The instrument air compressors will be powered from an emergency bus and be located in the auxiliary building.
The meeting brief identified two primary issues for licensee resolution:
a.
The compressor control logic will be reviewed to ensure it is optimum for operator control and plant reliability concerns, and b.
The proposed sequence for equipment installation and removal will be reviewed. to ensure that the risk to the station of a loss of instrument or service air is minimized.
The inspectors will continue to follow the system upgrade during its planned installation in the remainder of 1989.
11. Actir.n on Previous Inspection Findings (92701, 92702)
(Closed) Violation 338,339/87-36-02, Failure To Follow Procedures And Inadequate Procedures.
This violation involved five examples for failure to follow procedures-and inadequate procedures. The inspector reviewed the licensee's ccrrective actions taken for each example of the violation and concluded that *Me steps taken to prevent recurrence were adequate.
The inspector res ;wed the completed work package and numerous administrative and plant procedures.
(Closed) Violation 338,339/87-09-01, Failure To Establish An Adequate Material Control And Accountability Procedure, And Failure To Conduct An Annual Physical Inventory Of Incore And Excore Detectors Which Contained Special Nuclear Materials. The inspector reviewed the licensee's response dated July 7,1987, and determined that new administrative procedure No.
19.28, Physical Inventory of SNM, was established and approved on July 9, 1987, to provide guidelines and responsible personnel for performing a physical inventory of all incore and excore detectors. The inspector also verified that a physical inventory of these detectors was being performed on a semi-annual basis.
The inspector concluded that the corrective actions stated in the violation response have been implemented.
(Closed) Violation 338/88-01-01, Failure to Follow Procedure And Failure To Have Adequate Procedure Resulting Ir. A 1000 Gallon Leak From The RCS.
The inspectora verified that the following corrective actions have been
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implemented:
a.
Station administrative procedure ADM-2.11, Quality Maintenance Team, was created and approved on February 2, 1988.
This procedure
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An operations miscellaneous procedure, MISC-37, Assessment of Maintenance Activities For Potential l Loss of RCS. Inventory, was developed on April 14, 1988, to assist operations personnel in better c.ssessing maintenance acti"ities' that could impact RCS inventory.
c.
Operating procedures 1 and 2-0P-5.4, Draining the Reactor Coolant System, were revised and approved on June 28, 1989 and July 6, 1989, respectively, to add an attachment to verify.the proper installation of the RCS standpipe level system, d.
Surveillance and test administrative procedure 34.0, Engineering Studies, was. revised and approved on March 15, 1988 to ensure.
enginereing evaluations of RCS level requirements. consider PRT c
pressure and standpipe level indicator inaccuracies.
In addition, the licensee is expecting to complete the upgrade of RCS level indication system for use during drained-down conditions at the end of the next refueling outage for each unit. Based on this information, this violation-is closed.
(Closed) Violation 338,339/88-05-01, Failure To perform Post-Maintenance Testing On Containment Isolation Valves Following Maintenance. The root cause of the violation was determined by the licensee to be an inadequate EWR which did - not require post-modification testing after work was performed on safety-related equipment. After the discovery of the EWR deficiency, the-isolation valves involved were tested and determined to be operable from the time the-original EWR was performed.
The inspector.
verified that ADM-3,7, Engineering Work Requests, was revised to require testing for all modification EWRs and SNSOC approval of all modification EWR packages.
Design change package administrative procedures concerning post-maintenance testing requirements were also revised.
The inspector considers this violation closed.
(Closed) Violation 338/88-22-02, Failure To Follow Procedure During Containment ' Entries.
The inspector reviewed the licensee's corrective actions regarding the violation and found them to be adequate.
In the immediate period following the issuance of the violation, performance during containment entries indicated that the licensee improved compliance with ADM 20.9, with no procedural non:ompliances identified.
This violation is closed.
(Closed) Violation 339/89-03-01, Service Water Vent Valve Left Open. The inspector reviewed the licensee's response to the violation dated May 18, 1989. The licensee's investigation to determine how SW valve 2-SW-242 was left open and uncapped was inconclusive. Therefore, no further valve and installation of the pipe cap. The inspector has no concerns at this time regarding the licensee's corrective actions.
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(Closed) Violation 338/89-03-02, Failure To Take Corrective Action On
. Water In The CAE Lines. The inspector reviewed the corrective actions taken in the licensee's response to the violation and 'found them to be complete. Tne water flowing through the radiation monitor when the air ejector is automatically diverted to containment was due to the breaking of a 9 seal during diversion. Check valves to the air ejector monitor on Ur i have been installed to prevent recurrence of the air ejector radiauon monitor problems. Check valves on Unit 2 already existed and no modifications were required.
(Closed) IFI 338,339/88-33-04, Adequacy Of The Containment Spray Addition l.
System. This IFI originated by a request from the resident inspector to
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the licensee's management on a commitment date for the review of an unreviewed ' safety question forwarded to the licensee by Westinghouse on November 6, 1988. The Westinghouse letter regarded the design of the containment spray system.
The inspector reviewed the results of the evaluation provided on December 29, 1988, and the record of telephone conversations from VEPCO to Westinghouse regarding the 'above, which occurred on December 28, 1988. The inspector believes that the licensee has adequately addressed the concerns raised by Westinghouse and considers this IFI closed.
(0 pen) IFI 338/88-22-01, Followup On The Root Cause Of The Unit 1 "C" Main Feedwater Isolation Valve To Close.
The licensee provided a root cause analysis' of the maia FW line isolation MOV dated October 7,1988. The licensee attributed the improper limit switch adjustments to.several factors, which, in combination, led to the FW-154C valve not to fully close during a reactor trip. Reviews of the most recent M0 VATS data taken revealed that of MOV's FW-154 A, B, C and 254 A, B, C, the 154C valve is th.e only one affected by an incorrect limit switch setting. The valve was set in this manner to prevent backseating or seating the valve with excessive thrust.
In order to improve the overall reliability of FW 154/254 valves, the licensee has submitted EWR 89-112 to perform modification recommendations transmitted in a memorandum to SNSOC on March 10, 1989.
Due to the long lead time associated with the installation of new motors, this work is due to be scheduled for the 1990-1991 refueling outages. As of August 10, 1989, the licensee plans to re-evaluate the North Anna MOV program based on the results of MOV modifications being accomplished at the Surry facility.
The final decision on the FW valve modifications will be determined after the Surry results have been incorporated at North Anna. This IFI will remain open pending a final review of the FW valve modifications in conjunction with the' Surry MOV program review.
(Closed) IFI 338,339/88-03-03, Ramation Work Permit Hold Program. This IFI is in response to a weakness identified regarding the licensee's programs to keep radiation exposures ALARA. The licensee has implemented a change to the Personnel Exposure Management System on March 31, 1989, which will automatically prevent any additional use of an RWP when the actual exposure for the RWP exceeds 125 percent of the projected exposure.
This change will implement an "ALARA Hold" on RWPs to prevent licensee
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personnel from _ logging in on RWPs that are in excess of the projected -
man rem.
The inspector-rev_iewed the licensee's work package and has no further concerns at. this time.
(Closed) IFI 339/87-42-01, Review Response To IEIN 87-25 And Human Performance Evaluation System Study.
The inspector reviewed the licensee's re-evaluation of IEIN 87-25, dated March 22, 1988, and found it to be adequate.
This IFI was generated by the resident inspector following a personnel error that caused an inadvertent start of the 2J EDG, and was an example of the kind of error IEIN 87-25 was intended to prevent.
The licensee's re-evaluation considered train and procedure color coding, procedure and component label improvements, and color coded signs which inform individuals which train they are on.
Busses and breakers were also painted to indicate train designation. The inspector also verified that-the recommendations of HPES87-173, concerning the inadvertent start of the 2J EDG, were adequate and properly implemented.
(Closed) IFI 338,339/88-21-01, Followup On Installation Of a Spool Piece To Ensure Resin Discharge Capabilities.
The licensee has completed modifications on September 12, 1988, which installed a 1-connection on the 2-inch resin line upstream of the spent resin hold-up tank.
This modification will allow resin discharge capability directly to a shipping liner, instead of removing a spool piece to perform the resin discharge.
The inspector reviewed the modification package and associated EWRs, and verified drawing and document revisions resulting from the modification were completed.
(Closed) IFI 338,339/88-21-02, Check Valve Installation On Recirculation
Lines To The Motor Driven AFW Pumps. The licensee installed check valves
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in each of the pump recirculation lines to prevent backflow through the idle pump for both units. The inspector reviewed the modification package dated June 30, 1989, and has no further concerns.
(Closed) IFI 338/88-11-03, Low Head Safety Injection Pump Suction Valve Leakage.
On June 17, 1988, the licensee provided information concerning Type "C" testing (per Appendix J of 10 CFR 50) of the LHSI pump suction valves.
The inspector reviewed the applicable UFSAR section and the licensee's explanation of the exemption from Type "C" testing for these valves.
The piping for this system is below water level under post accident conditions and therefore would be a water leakage versus air leakage path.
Failures of the LHSI subsystem and component piping were shown to prevent containment leakage and would not result in an offsite release if a failure occurred.
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Exit The inspection scope and findings were summarized on August 22 with those persons indicated in paragraph 1.
The inspectors described the areas 1nspected and discussed in detail the inspection results listed below.
The licensee did not identify as proprietary any of the material provided l
to or reviewed by the inspectors during this inspection. A dissenting
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comment - was received from the licensee involving the viobtion.- The o
licensee stated that 'it was not' their normal policy to perform a procedure for the first time on an; operating unit. The licensee further stated that
.they would normally test the procedure first, however the NRC required the procedure to be performed.
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Item Number Description and Reference 339/89-26-01 Violation: Failure to have adequate surveillance procedures to perform ESF slave relay testing with three examples (paragraph 4).
338,339/89-26-02 Unresolved Item: Potential electrical separation problems (paragraph 6).
338,339/89-26-03 Unresolved. Item:
Potential inoperability of the required pressurizer heaters due to high ambient temperatures (paragraph 6).
338,339/89-26-04 Unresolved Item:
10 CFR 50.59 review of the 1-Unit 2'. mechanical overspeed test of the main turbine (paragraph 9).
338/89-26-05 Inspector Followup Item:
Followup
~on deficiencies found during the Unit 1 AFW walkdown (paragraph 5).
The inspector also discussed concerns raised to station management as described in paragraph 6.
13.. Acronyms and Initialisms AFW Auxiliary Feedwater-ALARA As Lo-
- s Reasonably Achievable AP Abnormm, Procedure ATWS Anticipated Transient Without Scram ASLB Atomic Safety Licensing Board AMSAC ATWS Mitigating System Actuation Circuitry l'
CAE Condenser Air Ejector CFR Code of Federal Regulations DCP Design Change Package EDG Emergency Diesel Generator EHC Electro-Hydraulic Control EP Emergency Procedure EQ Equipment Qualifications ESF Engineered Safety' Feature EWR-Engineering Work Requests FW Feedwater FQ Heat Flux Hot Channel Factor
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HP Health Physics
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HPES Human Performance' Evaluation. System-IEIN-Inspection and Enforcement Information Notice IFI Inspector Follow-up Item JC0 Justification for Continued Operation LCO Limiting Condition for Operation LER
' Licensee Event Report LHSI Low Head Safety Injection LOCA Loss of Coolant Accident MOV Motor Operated Valve NRC Nuclear Regulatory Commission NSE-Nuclear Safety Engineering PCT-
. Peak Clad Temperature PSIG Pounds Per Square Inch Gauge QA Quality. Assurance RCS Reactor Coolant Syttem
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RPM Revolutions Per Minute RWP Radiation Work Permit l-RWST Refueling Water Storage Tank
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. Systematic Assessment of Licensee Performance
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SJAE-Steam Jet Air Ejector SNM Special Nuclear Material SNSOC Station Nuclear Safety and Operating Committee 50V.
Solenoid Operated Valve SSOMI-Safety System Outage' Modification Inspection SSPS'
Solid. State Protection System-SW Service Water T(hot)
Hot Leg Temperature TI Temporary Instruction TS..
Technical Specification UFSAR Updated Final Safety Analysis Report
.VEPCO Virginia Electric and Power Company t
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