IR 05000313/1989010
| ML20246P360 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 05/15/1989 |
| From: | Chamberlain D, Haag R, Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20246P327 | List: |
| References | |
| TASK-2.F.2, TASK-TM 50-313-89-10, 50-368-89-10, IEB-84-02, IEB-84-2, NUDOCS 8905220157 | |
| Download: ML20246P360 (17) | |
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S LAPPENDIX'B'
o V. S. NUCLEAR REGULATORY COMMISSION REGION'IV--
inspection Report: 50-313/89-10 Licenses: DPR-51 50-368/89-10 NPF-6 Dockets:
50-313 50.368
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Licensee: Arkansas _ Power & Light. Company (AP&L)-
j P. O. Box'551
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Little Rock, Arkansas 72203
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Facility Name: Arkansas'NuclearOne(ANO), Units 1and2
' Inspection'At: AN0 Site Russellville, Arkansas
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Inspection Conducted: March 1 through April 15, 1989'
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Inspectors:
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N. D. J,pfinson,: Senior Resident Inspector, Date '-
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- Projfet Section A,' Division of Reactor:
Proj ects -
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- R. C. Haag, Resid6nt Inspector, Project Date
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Section A, Division of-Reactor Projects
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Approved:
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E f/89 D. D. Chamberlain, Chief, ' Project Date
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Section A Division of Reactor Projects l
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l 8905220107 890515 PDR ADOCK 05000313 Q
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Inspection Summary Inspection Conducted March 1 through April 15, 1989 (Report 50-313/89-10; 50-368/89-10)
Areas Inspected:
Routine, unannounced inspection including plant status, followup of events, followup on IE Bulletins and the ATWS Rule (10 CFR Part 50.62), operational safety verification, monthly maintenance observation, nonthly surveillance observation, followup on TMI action items, and evaluation of licensee quality assurance program implementation.
Results: Three examples of inadequate corrective action were identified. The first case involved the initial corrective action for K-Line circuit breakers that did not adequately address the problem.
The corrective action is being further reviewed. Two other examples involved a bent vent stack and the qualified life of Agastat relays in which previous corrective action did not resolve the concerns. These issues were recently readdressed by the licensee.
The failure to properly implement a procedure for the calibration of a decay heat removal flow transmitter resulted is an apparent violation. The wrong flow transmitter was isolated for the calibration which resulted in a loss of decay heat flow indication and the subsequent securing of the decay heat removal pump. The failure to implement the ATWS Rule modification specifications by May 1988 is an apparent violation of 10 CFR Part 50.62.
Increased management attention is needed to determine the root cause of the large number of recent control room emergency ventilation system actuations and to provide effective corrective action. This large number of inadvertent actuations is indicative of poor system reliability.
An in-office evaluation of the effectiveness of the licensee's quality assurance program implementation was performed during this inspection period.
On the basis of this evaluation, negative trends in the licensee's performance in the areas of corrective action, control of safety-related activities, radiological controls, and NRC reporting requirements were noted.
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DETAILS 1.
Persons Contacted
- J. Levine, Executive Director, ANO Site Operations
- C. Anderson, In-House Events Analysis Supervisor
- B. Baker, Plant Modifications Manager T. Baker, Technical Support Manager D. Bennett, Mechanical Engineer S. Capehart, I&C Engineer B. Converse, Operations Assessnent Supervisor
- A. Cox, Unit 1 Operations Superintendent M. Durst, Project Engineering Superintendent B. Eaton, Manager, Mechanical, Civil and Structural Design E. Ewing, General Manager, Plant Support i
B. Greeson, Design Engineering Supervisor L. Gulick, Unit 2 Operations Superintendent
- L. Humphrey, General Manager, Nuclear Quality
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G. Kendrick, I&C Maintenance Superintendent
- R. Lane, Engineering Manager
- D. Lomax, Plant Licensing Supervisor D. McKenney, Electrical Engineer j
- J. McWilliams, Maintenance Manager
B. Michalk, Mechanical Engineer
- P. Michalk, Nuclear Safety and Licensing Specialist V. Pettus, Mechanical Maintenance Superintendent F. Philpot, Nuclear Engineering Superintendent
- S. Quennoz, General Manager C. Shively, Plant Engineering Superintendent C. Taylor, Unit 2 Operations Technical Support Supervisor L. Taylor, Nuclear Safety and Licensing Specialist R. Tucker, Electrical Maintenance Superintendent J. Vandergrift, Operations Manager B. Williams, Electrical Engineering Supervisor C. Zimmerman, Unit 1 Operations Technical Support Supervisor
- Present at exit interview.
j The NRC inspectors also contacted other plant personnel, including operators, technicians, and administrative personnel.
2.
Plant Status (Units 1 and 2)
Unit I remained shut down for maintenance and modification of items
'j identified following the reactor trip on January 20, 1989, until the unit was returned to critical operation on March 30, 1989. The unit reached 50 percent power operation on April 1,1989, and remained at that power through the end of the inspection period.
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The reduced power operation resulted from an amendment to the facility operating license issued on March 29, 1989, that limited the authorized power to 50 percent of rated thermal power for 50 effective full power days. This is discussed in further detail in Paragraph 3 of this report.
3.
Followup of Events (Units 1 and 2) (93702)
a.
Licensee Report of More Limiting LOCA Scenario Than Previously Analyzed On March 18, 1989, with Unit 1 in cold shutdown, the licensee reported that they had discovered a more limiting small break loss of
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coolant accident (LOCA) scenario than had been previously analyzed by l
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Babcock and Wilcox (B&W). The previously assumed limiting break was a small break in one reactor coolant system (RCS) cold leg. The high pressure injection (HPI) system under that condition would initially pass 50 percent flow out of the postulated break and 50 percent flow l
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Plant operators could then manually balance flow and achieve 70 percent flow into the core. The new limiting i
break location was found to be a break of one HPI line just upstream i
of the RCS cold leg.
Initially under this postulated break condition, 100 percent flow would go out the break. Operators could then i
manually balance only 50 percent of the flow into the core. With only 50 percent flow, the peak clad temperature limit of 2200*F may be exceeded if the break occurs with the plant at 100 percent
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power.
l A licensee. submittal to the Office of Nuclear Reactor Regulation has demonstrated that continued safe operation of the plant at 50 percent power on a temporary basis (50 effective full power days) is justified by engineering analysis. The licensee is continuing to
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work with B&W in order to demonstrate that continued operation up to l
74 percent of rated thermal power can be attained without exceeding I
the limits of 10 CFR Part 50, Appendix K.
Although this issue has
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j not been fully resolved, it appears that modifications to the HPI I
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syster:: will be required before 100 percent power operations can be
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resumed. The licensee has stated that B&W has indicated that this problem is unique to ANO, Unit 1, because of the configuration of the HPI system. An amendment to the facility operating license was issued on March 29, 1989, which limits the authorized power to 50 percent of rated thermal power for 50 effective full power days.
l NRC followup of this matter will be tracked by inspection followup
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(Item 313/8910-01).
Unit 2 operated at or near 100 percent throughout the inspection period.
b.
Loss of Decay Heat Removal Flow Indication On March 14, 1989, decay heat removal (DHR) flow indication was lost on Unit 1 while in a cold shutdown condition. After receiving the l'
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" Decay Heat Removal Flow Low" annunciator and observing zero indicated flow, control room operatces secured the operating DHR pump in accordance with the abnormal operating procedure. The cause of the annunciator and the zero flow indication was the incorrect isolation of the DHR flow transmitter.
Instrument and Control (I&C)
technicians were tasked to perform a calibration of Transmitter PDT-1401 which provides a flow signal for "A" DHR train.
However, Transmitter PDT-1402 which provides a flow signal for "B" DHR train was inadvertently isolated. This resulted in the loss of indicated flow for the operating "B" DHR pump. Actual DHR flow was lost when control room operators secured the "B" DHR pump due to loss of flow indication.
Plant operators promptly identified that the isolation of the wrong transmitter was the cause of the loss of "B" train flow indication. They subsequently restored DHR flow and indication within 13 minutes. On the basis of the abnormal operating procedure requirement that the DHR pump be secured on a loss of DHR flow and the timeliness of restoring DHR flow, operator action appeared to be appropriate.
PTP 1304.013, Revision 8, "HPI/LPI and Reactor Building Spray Flow Instrument Surveillance Red Channel," which provides calibration instructions for instruments in the "A" train, incorrectly noted that the location of PDT-1401 was in the "B" Decay Heat Vault. However, Transmitter PDT-1401 was properly referenced in the procedure. Also, the flow transmitter in the "B" DHR train that was inadvertently isolated was correctly labeled as PDT-1402. The failure to properly implement Procedure 1304.013 when calibrating Transmitter PDT-1401 and the subsequent isolation of Transmitter PDT-1402 is an apparent violation (313/8910-02).
c.
Air Pocket in the Service Water Supply to the Emergency Feedwater
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i System The NRC inspector reviewed the applicability to ANO of a concern identified at Wolf Creek Nuclear Station that dealt with an air pocket in the suction line to the emergency feedwater (EFW) pumps.
Service water is used at ANO as the secondary water supply to EFW and is actuated on low condensate tank pressure.
For Unit 2, both trains of service water are connected to the EFW suction piping. !! small section of piping between a check valve and motor operated valve in each train is normally drained. The piping is drained to prevent service water leakage past the motor operated valves from entering the normal EFW supply.
For Unit 1, service water piping is vented and remains full at the EFW suction piping; therefore, the concern of an air pocket does not exist.
The licensee calculated the total volume of air in the drained portion of the service water supply line to be 1.3 cubic feet. The pump and turbine vendors were consulted on the possible effects of l
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the air pocket.. On the basis of the following justification, the licensee determined the air pocket in the service water piping would not degrade EFW operation.
- The pump vendor stated 1.3 cubic feet of air would not damage the pump but that repeated occurrences of air slugs going through the pump is not desirable. On'the basis of the low probability of service water being used as the supply to EFW, the licensee concluded that this is not a concern.
The turbine vendor stated that the control system for the turbine would prevent the turbine from tripping on overspeed when the air passes through the pump.
- On the basis of the slow opening times of.the motor operated valves and the length of suction' piping.from the air pocket location' to the EFW pump, the' air will tend to disperse within the system fluid..
The NRC inspector reviewed the licensee's response concerning this issue and determined the engineering justification adequately resolved the concern related to an air pocket in the service water supply to the EFW system.
d.
Unit 1 Shutdown Margin Concern The licensee was notified by B&W via a letter dated February 22, 1989, of a potential concern related to insufficient shutdown margin-for Unit 1.
This situation could exist when reactor power is less than 15 percent or reactor coolant temperature is above 280*F and steam generator (SG) level is raised over 40 inches. These conditions would not satisfy the initial conditions for the main steam line break (MSLB) accident analysis since the analysis assumed a minimum inventory in the SGs at low power and a maximum inventory at high power.
In response to this concern, the licensee reviewed the procedures governing operation at low power and shutdown conditions and the practices of maintaining SG levels during these conditions. These procedures were subsequently revised to explicitly identify the need for additional shutdown marHn if SG 1evels are raised above 40 inches.
In addition, the calculation of shutdown margin for low power and shutdown conditions was revised. The licensee is still reviewing plant records in order to determine if the plant was ever outside of its design basis for the MSLB accident anlaysis. The NRC inspectors will track the resolution of this issue by inspector followup (Item 313/8910-03).
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e.
High Pressure injection Piping Interferences The NRC was notified by the licensee on March 20, 1989, of a potential interference condition between a high pressure safety injection check valve, located inside the reactor building, and a structural beam. While performing a postmodification inspection, licensee engineers identified insufficient clearance between MU-34B and an overhead beam. A gap of 1.75 inches is required for thermal movement; however, the existing gap was only 0.5 inch. Also identified was a bent vent stack downstream of MU-34B. This was also caused by structural interference. The following corrective action resulted from these interference problems:
A section of pipe and two elbows downstream of MU-34B wete replaced because the piping had been overstressed from the limited thermal movement.
The beam above MU-34B was modified to provide the required gap for thermal growth.
The vent stack was replaced with a shorter vent stack that was
inclined away from the adjacent. structure.
The other high pressure injection lines were inspected to ensure existing gaps were sufficient for thermal growth.
During the review, the NRC inspector noted that the bent vent stack had been identified in September 1988 by an isometric update inspection. A plant engineering action request (PEAR) was dispositioned by requiring the performance of a dye penetration inspection of the vent stack welds and notching the beam that was in contact with the vent valve. The PEAR did not address the amount of clearance required due to the thermal growth of tne piping at the vent stack location. The PEAR resolution was to require the enlargement of an existing notch in the beam "as required" to clear the vent valve. Also provided on the PEAR was the maximum size of the notch. The root cause of the bent vent stack, i.e. insufficient clearances for thermal growth, was not corrected by the PEAR. The NRC inspector was concerned that more indepth review of resolutions to plant deficiencies may be appropriate to ensure that the root cause is identified and corrected.
f.
Qualified Life for Agastat Relays Condition Report (CR) C-89-050 documented that 262 Agastat time delay relays utilized in Units 1 and 2 have exceeded the 10-year design qualified life. Amerace/Agastat Test Report ES-1000 specifies a 10-year limited life or 25,000 cycles for nuclear grade relays. The
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majority of the installed Agastat relays at ANO were procured to commercial grade requirements. Of the 262 relays, 99 relays serve safety functions and required further review for their continued use.
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The licensee used the following infornetion to justify the continued use of the 99 relays during the remainder of the operating fuel cycles:
All the relays were installed in rooms with controlled temperatures. The highest room temperature is 95 F, which is within the Agastat relay temperature operating range of 70 F to 105"F.
The number of operating cycles the relays have experienced are significantly below the 25,000 cycles used in the qualification test.
The failure rate for Agastat relays at ANO and industry wide has been very low.
All the relays are functionally tested to demonstrate the overall ability of the relays to perform their safety-related functions. These tests are part of the overall test program at ANO and were not performed specifically for the qualification of Agastat relays.
The NRC reviewed the basis for the licensee's engineering judgment to allow continued use of the Agastat relays and found it to be acceptable. The NRC inspector will follow up on the licensee's plans to replace the Agastat relays during the next refueling outages.
The issue of qualified life for Agastat relays has been previously identified at ANO but had not been resolved. NRC Inspection Report 50-313/86-17; 50-368/86-18 discussed certain types of components having a design-limited service life and noted Agastat time delay relays as an example. kRC Information Notice 87-66,
" Inappropriate Application of Commercial-Grade Components," discussed the 10-year projected qualified life for nuclear grade Agastat relays and a 2-year projected qualified life for commercial grade Agastat relays. A review by the licensee indicated the 10-year qualified life issue was discussed in correspondence dating back as far as 1979 and then more recently in 1983. On the basis of the above, the licensee had previous knowledge that the issue of qualified life for Agastat relays was a concern at AN0 and needed resolution.
The initial resolution to the condition of a bent vent stack in the high pressure injection piping and the issue of qualified life for Agastat relays are two examples of the licensee's failure to provide adequate corrective action. The effectiveness of the licensee's corrective action program has been the subject of recent NRC l
inspection reports and a subject of a recently proposed imposition of a civil penalty. As a result, these examples will not be cited as a
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violation in this inspection report. Licensee management should l
review these examples, however, to determine if additional action is required for the corrective action progra i q
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4.
Followup (Unit 2)
(92701)
a.
IE Bulletin 84-02 This bulletin, entitled " Failures of General Electric Type HFA Relays
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in use in Class 1E Safety Systems," was issued on March 12, 1984.
The licensee provided written responses to this bulletin in letters
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dated July 20, 1984, and February 11, 1985.
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The licensee's response informed the NRC of a similar problem l
exwrienced with Potter & Brumfield (P&B) Model MDR 137-8 and NUR 138-8 relays in Unit 2.
Failure investigations conducted by both the licensee'and P&B showed-the cause of failure to be outgassing of
the coil varnish.
During the sixth refueling outage 92 P&B Model MDR 137-8 and MDR 138-8 relays were replaced with new P&B Model MDR-5138 and MDR-5139 relays. The new relays were identical to the older model relays with the exception of the coils which have an epoxy finish in lieu of a varnish finish. The NRC inspector reviewed the completed design change package. This bulletin is closed.
b.
Implementation of Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events Between January and March 1989, NRR conducted a review of ATWS Rule (10 CFR Part 50.62) related correspondence between AP&L and the NRC to support the evaluation of a recent AP&L ATWS submittal for ANO, Unit 2.
During this review, it was determined that the ATVS implementation deadline for_ANO, Unit 2 had passed without AP&L installing the equipment specified by 10 CFR Part 50.62. Specifically, the Unit 2 deadline was May 1988 based on the completion of three refueling outages after July 26, 1984. Since there was no requested
or approved scheduler extension for Unit 2, this is an apparent
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violation of 10 CFR Part 50.62(368/8910-03).
5.
Operational Safety Verification (Units 1 and 2)
(71707 and 71710)
The NRC inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators. The NRC inspectors verified the operability of selected emergency systems, reviewed tag out records and verified proper return to service of affected components, and ensured that maintenance requests had been initiated for equipment in need of maintenance. The NRC inspectors made spot checks to verify that the physical security plan was being implemented in accordance with the station security plan. The NRC inspectors verified implementation of radiation protection controls during observation of l
plant activities.
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-The NRC inspectors toured accessible areas of the units to observe plant I
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equipment conditions, including potential fire hazards, fluid leaks, and excessive vibration. The NRC inspectors also observed plant housekeeping and cleanliness conditions during the tours.
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The NRC insp(ectors walked down the Unit 1 emergency dieselEDGs) and suppo The walkdown
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generators
was conducted using Attachments A and B to Procedure 1104.36, Revision 26,
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" Emergency Diesel Generator Operations." Drawing M-217, Sheets 1, 2, and 3 were also used during the preparation and conduct of the walkdown inspection. While no system misalignment or operability concerns were identified, the NRC inspectors identified several minor discrepancies for licensee corrective action. The following material discrepancies were identified:
The tachometer for the "A" EDG read 300 RPM with the engine shut
down.
An oil leak was noted on a fitting on the "A" EDG in front of
PS-5272.
PI-5259 was pegged high with the engine shut down. The gage was
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facing the wrong direction, making it difficult to see the gage face.
This gage indicates cooling water pump discharge pressure for the
"A" EDG.
Valve F0-43132 had no identification label.
- The loose end_ of the hose used to add fuel oil to diesel fuel storage tanks was not covered and was pointed upward such that rain could enter the hose.
Procedure 1104.36, Revision 26, was issued since the last valve lineups of these systems were performed by plant operators. The following discrepancies were noted on the valve lineup attachments of Procedure 1104.36, Revision 26:
Attachment A indicated that Valve F0-5274C should be open. This instrument line drain was closed and should normally be closed.
Attachment B contained a similar discrepancy for Valve F0-5275E.
The descriptions in Attachment B for Valves F0-1066J and F0-1066M appeared to be in error. Valve F0-1066J is a vent on the supply to an air box trap, but was described as a strainer blowdown valve.
Valve F0-1066M is a strainer blowdown valve but was described as a vent.
Valve F0-172 on Attachment B should be F0-171.
- LicenseeEventReport(LER) 50-368/89-004 documents a condition that
alone could have prevented the fulfillment of the safety function of a
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system needed to mitigate the consequences of an accident for Unit 2.
j TS 3.5.3 requires that one high pressure safety injection (HPSI) pump be j
operable in Mode.4 with the capability of automatically transferring the
pump suction to the containment sump on a recirculation actuation
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signal (RAS). During a review of the Unit 2 startup Procedure 2102.02, j
Revision 28, the licensee identified that the circuit breakers for the containment sump isolation valves are tagged open until the unit is at approximately 300 F (entering Mode 3). This condition would have i
prevented the automatic transfer of the pump suction to the containment sump while in Mode 4.
The plant start up procedure was revised to ensure that the containment sump isolation valves are fully operable prior to entering Mode 4.
This event will be reviewed and documented in NRC Inspection Report 50-313/89-22; 50-368/89-22.
While touring the Unit I auxiliary building, the NRC inspector observed the recent painting and upgraded housekeeping efforts in the emergency feedwater pump room and makeup pump rooms. Also noted were the decontamination effort.s in the makeup pump rooms that have reduced the amount of contaminated areas in these rooms. The NRC inspector noted that these and similar plant upgrade efforts will allow more effective maintenance and operation of the plant.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under TS, 10 CFR, and administrative procedures.
No violations or deviations were identified.
6.
Monthly Maintenance Observation (Units 1 and 2)
(62703)
Station maintenance activities for the safety-related systems and components listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards and in conformance with the TS.
The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service, approvals were obtained prior to initiating the work, activities were accomplished using approved procedures and were inspected as applicable, functional testing and/or calibrations were performed prior to returning components or systems to service, quality control records were maintained, activities were accomplished by qualified personnel, parts and materials used were properly certified, radiological controls were implemented, and fire prevention controls were implemented.
Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority is assigned to safety-related equipment maintenance which may affect system performance.
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The following maintenance activities were observed:
. Seat leak testing of Check Valve MU-34B (Procedure 1305.19).
Following modifications of the MU-34 valves to prevent the. valves from hanging open, a seat leakage test was performed. The newly installed Stop Check Valves MU-66A, -B, -C, and -D were also seat leak tested.
Ultrasonic testing of welds in the decay heat removal discharge
piping (Procedure 1092.028). The inspection of these welds was a portion of the licensee's overall effort to evaluate deficiencies in the decay heat removal piping and to identify any additional problems.
Coupling alfgnment for Reactor Building Spray Pump P-35A (Procedure 1402.003, Job Order 777520). The pump-to-motor coupling was realigned following replacement of a motor bearing.
Repair of packing steam leak on the Governor Valve CV-6601 for the
Unit 1 emergency.feedwater pump turbine (P7A) (Procedure 1402.159, Job Order 744710). After disassembly, the licensee discovered that the inner packing snap ring and eight rings of c,;rbon packing were missing. Also the inner land area in the bonnet, where the snap ring fits, had eroded such that the snap ring would not be retained in the bonnet.
The licensee theorized that the eroded land allowed the snap ring to slide down the stem and loosened the packing. Steam then leaked by the loose packing and, eventually, the carbon packing and snap ring disintegrated due to steam erosion. The licensee also believed that leaking steam caused the steel packing spacers to rotate on the stem which resulted in a significant reduction of stem thickness. A temporary modification welded a washer to the valve bonnet to retain the inner snap ring in the proper location. A new stem was installed. The licensee has ordered a new bonnet.
In response to these deficiencies, the licensee disassembled and turbine (2P7A) governor valve for Unit 2 emergency feedwater pump inspected the It was discovered that the packing had seized to the
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valve stem and was moving with the stem, in lieu of the stem sliding through packing. The inner packing snap ring was missing; however, damage to the snap ring land area in the bonnet and reduced stem thickness were not identified. The valve was reassembled with a new stem and packing.
The licensee has indicated that the corrective action for the i
condition reports that identified the discrepancies on the governor i
valves will address periodic inspections of the valves. The NRC
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inspector will review the licensee's corrective action.
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Vibrational analysis of HPSI Pump 2P-89A and Low Pressure Safety
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Injection (LPSI) Pump 2P-60A. Previous analysis of the motor bearing lubrication oil for 2P-60A identified higher than normal inorganic material and ferrous wear particles in the oil. Oil samples from 2P-89A also indicated a need for additional monitoring. The l
vibration analysis results indicated normal vibration for 2P-60A and slightly higher than normal axial vibration for 2P-89A outer motor bearing. The licensee suspects that the slightly higher than normal vibration for 2P-89A may be indicative of minor misalignment of the pump and motor. The licensee plans to realign the pump and motor following the planned replacement of the pump seal.
On the basis of results of the earlier oil samples, the oil sumps were flushed and the oil sampling frequencies have been increased from 18-month to 3-month intervals.
Because the oil sampling program is new, the licensee does not have baseline date for use in comparison of the oil samples.
Temporary modification on Unit 1 integrated control system (Temporary
Modification 89-1-005, Job Order 782913). The band on the neutron error was changed from plus/minus 1 percent to plus/minus 1.5 percent. When neutron error exceeds the limits of the band, the control rods are provided an inward or outward signal'(depending on errorsign). While operating at 50 percent power, the neutron error signal and control rod movement cycled frequently. This temporary modification was intended to reduce the frequency of neutron error exceeding the limits of the band and, therefore, reducing control rod movement.
Temporary modification to install diodes across the coils of solenoid
operated Valves 2SV-8683-1, 2SV-8683-2, 2SV-8685-1, and 2SV-8685-2.
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(Temporary Modification 89-2-003, Job Order 793380). These solenoid valves control instrument air flow to the control room (CR)
ventilation dampers. When the solenoid valves are deenergized, air is bled off and the dampers will close. The licensee believes the voltage surges associated with the coils deenergizing caused spiking of the Unit 2 radiation monitor and the subsequent actuation of the CR emergency ventilation system. During this inspection period of March 1 through April 15, 1989, there were 14 actuations of the CR emergency ventilation system. The diodes were instelled on April 14, 1989. After installation of the diodes, the dampers were cycled with no observable increase in radiation levels or spiking from the CR radiation monitor.
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The licensee has since experienced four actuations of the CR emergency ventilation from April 17-21, 1989. The cause of these actuations has not been determined. Heightened licensee attention is
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needed to identify the causes related to these actuations and to provide sufficient corrective action. The NRC inspector will monitor the licensee action,
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Replacement of the exhaust manifold transition piece on Unit 2 EDG (Procedure 2306.005,JO763543). The upstream joint on the exhaust manifold transition piece was the location of leaking oil and fires during previous surveillance tests of the diesel generator.
Inspection of the old transition piece revealed both flanges were warped.
The NRC inspector observed a subsequent run of the EDG to investigate an earlier reported fuel oil leak at a fuel injector. No fuel oil leak was identified. The NRC inspector noted the EDG was incrementally loaded in 5-minute intervals to fully load the diesel generator to 2850 kilowatts. Little exhaust smoke and no oil leakage from the exhaust manifold was noted during the run. During previous monthly tests, smoke and oil leakage and exhaust manifold fires were observed when the diesel was loaded to 2850 kilowatts within 60 seconds as required by the TS. The NRC inspector will continue to monitor diesel generator surveillance testing and future licensee actions.
Repair of Charging Pump 2P-36B (Procedure 2406.032,JO782336).
Corrective maintenance of the pump was performed because of reduced flow caused by the middle suction check valve loosening from an interference fit in the manifold block and coming in contact with the plunger. This condition occurred during postmaintenance operation of the pump for repairs caused by an outer suction check valve coming out of the manifold block.
Investigation by the licensee revealed that the check valves were not properly " seated" in the tapered portion of the manifold block. To correct this condition, the bottom of the new check valves were skim cut approximately 0.050-inch.
At the end of the inspection period, the licensee had not determined if the problem associated with the suction check valve installation was applicable to Charging Pumps 2P-36A and C.
The NRC inspector expressed his concern to the licensee that this determination be made expeditiously since this type failure could affect both pumps. The NRC inspector will review the licensee's applicability determination
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and any resulting corrective actions.
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Replacement of pipe hanger lugs on DHR piping (Design Change Package 89-1006). The licensee replaced the two lugs that were l
sheared off the pipe at Hanger DH-122 and relocated two other lugs to provide uniform clearance between all the lugs and the hanger support.
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These lugs were lengthened to allow the welds to be outside of the indented areas on the pipe.
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i In addition to the items above, the NRC inspector reviewed the licensee's l
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corrective action for the K-Line circuit breakers that failed to operate properly after installation of a rebound spring. Two safety-related breakers would not reclose and several nonsafety-related breakers experienced other problems when cycling the breakers. The cause of the
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I breakers failing to operate properly was the accumulation of dust, dirt, and dried lubricant on the internal surfaces which caused binding of the internal closing mechanism.
The initial corrective action to prevent recurrence for the generic concern of K-Line circuit breakers binding due to debris on internal surfaces was to be addressed by the new preventive maintenance (PM)
program.
The NRC inspector reviewed the new PM procedure for K-Line circuit breakers. Procedure 1412.043 only requires vacuuming of
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accessible areas and does not require cleaning of internal surfaces. The i
NRC inspector notified the licensee that the new PM procedure may not prevent recurrence of this problem. The licensee has issued additional corrective action items to further review this matter. Open Item 313;368/8905-02 was previously issued to track this matter and will continue to be used for tracking purposes.
No violations or deviations were identified.
7.
Monthly Surveillance Observation (Units 1 and 2)
(61726)
The NRC inspector observed the TS required surveillance testing on the various components listed below and verified testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with TS and procedure requirements, test results were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The NRC inspector witnessed portions of the following test activities:
Semiannual testing and calibration of the seismic peak shock recorders (Procedure 2304.058, Job Order 778599).
Eighteen-month calibration of the Gaseous Effluent Radiation Monitor RX-9835 for Unit 1 emergency penetration room ventilation system (Procedure 1304.140, Job Order 778588).
Leak test of Unit 1 emergency escape airlock (Procedure 1304.020, Job Order 777284). This test was performed due to maintenance on the airlock completed during the recent outage.
Special testing of Unit 2 Emergency Feedwater Purrp 2P-78 (Special Work Plan 2409.151). This test was performed to gather data on pump performance parameters, i.e., vibration, fluid temperature rise across the pump, and bearing temperature while operating the pump with only minimum flow. The test data was obtained to evaluate the adequacy of the minimum flow in response to NRC Bulletin No. 88-04, i
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" Potential Safety-Related Pump Loss," and to evaluate the recent L
reduction in measured minimum flow when the flow instrumentation was l'
recalibrates.
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No violations or deviations were identified.
8.
-Followup on TMI Action Item II.F.2 (Units 1 and 2)
On the basis of a site visit on August 10, 1988, the NRC Office of Nuclear
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Reactor Regulation completed its implementation review of ANO, Units 1 and 2 instrumentation for detection of inadequate core cooling (ICC). The NRR Safety Evaluation, issued on March 23, 1989, concluded that the ICC systems at ANO are performing satisfactorily and meet the design and operation requirements specified in NUREG-0737, Item II.F.2.
The licensee was requested to submit the required TS changes within 90 days of receipt of the March 23, 1989, letter and Safety Evaluation.
No violations or deviations were identified.
Inspection activities
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associated with TMI Action Plan Item II.F.2 are consistered complete.
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9.
Evaluation of Licensee Quality Assurance Program Implementation (Units 1 and 2)
(35502)
Regional management performed an evaluation of the effectiveness of the
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licensee's quality assurance (QA) program implementation by conducting on March 2, 1989, an in-office evaluation of the following:
NRC inspection reports for the past 12 months Systematic assessment of licensee performance (SALP) reports for the
past 2 years Region IV outstanding open items list
Licensee corrective actions for NRC inspection findings Licensee event reports for the past 12 months
On the basis of this evaluation, regional management determined that there were negative trends in the licensee's performance in the areas of corrective action, control of safety-related activities, radiological controls, and NRC reporting requirements. On the basis of previously performed NRC inspections, both scheduled and reactive, and scheduled upcoming NRC inspections, the regional management determined the currently planned inspection for ANO is sufficient to adequately review licensee activities during this SALP cycl,,
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j 10. Exit Interview The NRC inspectors met with Mr. J. M. Levine, Director, Site Nuclear Operations, and other members of the'AP&L staff at the end of the inspection. At this meeting, the inspectors summarized the scope of the inspection and the findings.
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