IR 05000313/1990019

Insp Repts 50-313/90-19 & 50-368/90-19 on 900601-0715. Violations Noted.Major Areas Inspected:Onsite Followup of Events,Operational Safety Verification,Surveillance,Maint & Design Changes

ML20058N982
Person / Time
Site:	Arkansas Nuclear
Issue date:	08/07/1990
From:	Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20058N977	List: IR 05000313/1990019 ML20058N974 ML20058N979
References
50-313-90-19, 50-368-90-19, GL-88-17, IEB-90-001, IEB-90-1, NUDOCS 9008150283
Download: ML20058N982 (17)

Text

,

, ..

'

.

APPENDIX B  ;

- - 1 U.S. NUCLEAR ~ REGULATORY COMMISSION i

REGION IV

Inspection Report: 50-313/90-19 Licenses: DPR-51 :

50-368/90-19 NPF-6 1 Dockets:- 50-313 50-368 Licensee: Entergy Operations, In ;

Route 3, Box 137G '

Russellville, Arkansas.'72801 Facility Name: Arkansas Nuclear One (ANO), Units 1 and 2 Inspection At: ANO Site, Russellville, Arkansas-Inspection Conducted: June 1 through July 15, 1990 Inspectors: C, C. Warren, Senior Resident Inspector Project Section A,-Division of Reactor Projects R. C. Haag, Resident Inspector I Project Section A, Division-of Reactor Projects

!

Approved: 7- I w N T.' F. Vestfrman, Chief, Project 5'ection A (2-- 7- f8 Date Division of Reactor: Projects Inspection Summa'ry i

Inspection Conducted June 1 through July 15, 1990 (Report 50-313/90-19: i 50-368/90-19)

Areas Inspected: Onsite followup of events, operational safety verification, i surveillance, maintenance, and design change ;

Results:

Violations:

Two apparent violations of NRC requirements occurred during this inspection period. One violation concerned the performance of an inadequate surveillance test (Section 5.0). The other violation was related to the failure to adequately document a condition adverse to quality (Section 6.3),

l 9008150283 900810 PDR ADOCK 05000313 Q PDC

,

_ _

... ..

-2-Observations:

Two personnel errors by members of the Unit 1 Operations staff, a power reduction due to excessive boric acid addition. and removal of the inservice condenser vacuum pump (Section 3.1) are further examples of operator inattention to detail. Although licensee management has placed high emphasis on reduction of personnel errors, the pattern continues and is of concer The Unit 2 reactor . trip of June 26, 1990, may have been avoided had the licensee's operability assessment of the faulty position indication for Control Element Assembly No. 29 not been so narrowly focused (Section 3,2). The licensee's Corrective Action Review Board recognized that the 1cck of a broad operability assessment was the primary contributor to the trip. The resident inspectors will closely follow licensee actions in this are *

Timely repair of an inoperable Unit 2 containment isolation valve was hampered by maintenance technician unfamiliarity with the valves (Section 6.1).

The licensee's condition reporting system has the potential to bypass high visibility balance-of plant issues (Section 3.3).

The licensee's decision to remove the Unit 2 turbine from service prior to effecting repairs to a cracked steam drain was conservative and safety

,

conscious (Section 3.3).

Work activities during forced outages continue to be well planned and executed.

,

t Licensee actions in response to Unit-2 instrument air system high dew point readings'were well planned and comprehensive (Section 6.1).

l

,

i i

!

-

.a

... .o

'

,

-3--

DETAILS PERSONS CONTACTED

• N. Carns, Vice President, Nuclear Operations '

J. Yelverton, Director, Nuclear Operations '

D. Boyd, Nuclear Safety and Licensing Specialist

'M. Chisum, Unit 2 Assistant Operations Manager K. Coates, Unit 2 Maintenance Manager A. Cox, Unit 1 System Engineering Superintendent

• R. Eddington, Unit 2 Operations Manager

• E. Ewing, General Manager, Technical Support'and Assessment

• R. Fenech, Unit 2 Plant Manager '

-J. Fisicaro, Licensing Manager

• L. Humphrey, General-Manager, Nuclear Quality

• J. Jacks, Nuclear Safety and Licensing Specialist

• King, Plant Licensing Supervisor J. Kowalewski, Mechanical Engineer: l

• G. Jones, General Manager, Engineering D. Mims, Unit 2 System Engineering Superintendent-

,

J. Mueller, Unit.1 Maintenance Manager

• J. Vandergrift, Unit 1 Plant Manager C. Zimmerman, Unit 1 Operations Manage D. Irving, Unit 1 Assistant Operations Manager '

B. Michulk, Mechanical Fnaineer

• E. Bickel, Managa- ..aiation Protection & Radiation Waste ,

• A. Jacobs, Supervisor, Surveillance Testing '

• R. Sessoms, Plant Manager, Central -

• Present at exit intervie ]

The inspectors also contacted other plant personnel, including aperators, engineers, technicians, and administrative personne , PLANT STATUS (UNITS 1 AND 2)

Unit 1 operated at 80 percent power throughout this inspection period, with the exception of the following short power reductions: .(1) a-plant runback to 37 percent on June 16, 1990, due to a dropped control rod; (2) a power reduction'to 70 percent on-June 23, 1990, due to an excessive addition of boric acid to the makeup tank; and (3)'a power reduction to 55 percent on July 3, 1990, that was requested by the system load dispatcher due to the loss of a 500-kV transmission lin Unit 2 operated at 100 percent power from June 1 until June 26, 1990, whe power was reduced to 0 percent for replacement of-a steam drain line. During the plant restart on June 26, 1990, the unit tripped from 30 percent power due to a faulty control rod indication. The unit restarted on June 28, 1990,-and

!

reached 100 percent power later that day. Power was reduced to 75 percent for l

!

-

... ..

.

-4-several hours on July 3,1990, as requested by the system load dispatcher due to the loss of a 500-kV transmission line. The unit was taken to cold shutdown conditions on July 14,-1990, for repair of leakage from the pressurizer code safety relief valve . ONSITE FOLLOWUP OF EVENTS (UNITS 1 AND 2) (93702)

3.1 Excessive Boric Acid Addition to the Makeup Tank / Condenser Vacuum Pump Breaker Misalignment On June 23, 1990, at 6:15 p.m., Unit 1 experienced a power reduction from 80 to 70 percent due to the addition of approximately 300 gallons of boric acid to the makeup tank. At the time of the event, an operator was making a

"no-concentration change" addition of 950 gallons to the makeup tank. The batch size was to consist of 28 gallons of boric acid and 922 gallons of demineralized water. The operator had completed the addition of 28 gallons of '

boric acid through the makeup systen batch controller. After the boric acid addition, the operator attempted to stop Boric Acid Pump P-39A. The batch controller was then set up to add the demineralized water. After approximately 3-4 minutes of the batch transfer, the operator noticed outward movement of the control rods. Several minutes later, a second outward rod movement occurred, at which time the operator recognizad that Boric Acid Pump P-39A was still'

operating. The pump was then secured and the inadvertent boric acid addition was stoppe The licensee's investigation of this event concleded that the cause of the boric acid addition was personnel error. While the oper ator apparently took action to stop Pump P-39A after the initial addition of. ?? gallons of boric acid, the operator did not verify that the pump had stopped. The licensee theorized that the operator may not have turned the pump hand switch to the full off position or that the hand switch for-the idle pump (P-39B) may have been manipulated in lieu of the Pump P-39A hand switc While the actual cause of Pump P-39A not being secured may not be known, it was apparent that the operator did not verify that his actions (securing the pump)

had been completed. Interviews with the operator indicated that he was knowledgeable of the task involving makeup tank addition and was fully aware of the need to secure Pump P-39A after the initial boric acid addition.

<

In response to the personnel error aspects of this event, corrective action was-issued for operations management to continue the emphasis on self-verificatio j The operator involved in this event was given the assige. ment of briefing the ;

other operations crews of the event and the need for self-verification of t operator action The assignment was completed within the next 2 working day On - July 12, 1990, while isolating a condenser vacuum pump breaker for maintenance,'an operator mistakenly racked out the breaker for the running pum The idle vacuum pump was started when the control room operatcr recognized that the condenser vacuum was decreasing and that the wrong breaker ,

had been racked out, i

l l

i

.. ..

~

.

-5-

'

Since the corrective action. involving personnel errors was recently completed and is now receiving additional review, the overall effectiveness of the corrective action has not been determined. Hcwever, due to the repetitiveness of these two recent personnel errors, and with the personnel errors in late 1989 that caused two reactor trips, the NRC considers that closer managemw

'

attention is warranted. The inspector will monitor the licensee's actions in response to these recent personnel error .2 Unit 2 Reactor Trip On June 26, 1990, a reactor trip occurred from 30 percent power, Position indication for Control Element Assembly (CEA) No. 29, actually at 99 inches, failed to an indication of 152 inche Control Element Assembly-Calculator (CEAC) No.1 sensed the deviation of CEA 29 from the group average CEA position and generated a large penalty factor. All four core protection calculators received the penalty factor and initiated a reactor trip. based on-exceeding the departure from nucleate boiling ratio and local power-density setpoint On June 9, 1990, while operating at 100 percent power, a "CEA sensor failure CEAC 1" alarm was received intermittently. Condition Report (CR) 2-90-247 was initiated to document these failures. The failed sensor status reports identified that CEA 29 was spiking high'as indicated by Reed Switch Position Transmitter (RSPT) 1. Subsequent troubleshooting identified that the source of the faulty indication was located in the containment building. While experiencing the intermittent spik l

was complying with the TS since RSing higF PT 2 an. theindication CEA pulseforcounting CEA 29,channel the licensee were operable,

'

During normal power operations, all CEAs are normally in the " full-out" position. When CEA 29 was in the full-out position, the spiking high indication did not generate a penalty factor from the CEAC. Based on the '

CR 2-90-247 operability assessment, the effect of CEA spiking high was evaluated for CEA 29 in the full-out position, but did not consider the affect of the spiking if CEA 29 was in an intermediate position. During the plant startup, while at 30 percent power, the part length rods (which includes CEA 29) were inserted to control axial power. It was dsring this' time, with CEA 29 out of its normal full-out position and with the indication spiking high, that the trip occurre The inspector attended the Corrective Action Review Board (CARB) review of this event. While several actions resulted from the CARB, the inspector considered the recognition of a weakness in the operability assessment process as an important element in the root cause determination for this even Specifically, the assessment of a deficient condition should include all'

possible modes of plant operation. Accomplishment of this task has been included as an action item on CR 2-90-247. The inspector will review the licensee's corrective action as followup of Licensee Event Report 368/90-19, which deteribes the event and resulting corrective actio I

..

'

.

-6- <

3.3 Failure of a Control Valve Body Drain Line On June 25, 1990, members of the Unit 2 operations staff noted a steam leak that appeared to be issuing from a flow orifice in the control valve body drain line. After removal of lagging in the area, it was determined that the piping downstream of the orifice blot.k had a split approximately 1-inch long. The damaged section of pipe was not i nlable from the high pressure steam in the control valve body, so the licensee decided to inject a leak repair compound into the orifice block in an attempt to stop flow through the crack. Attempts to stop flow using the leak repair compound were unsuccessfu The licensee considered encasing the entire section of pipe in a leak repair compound clamp and injecting compound until the leakage stopped, as well as hydraulically crimping the drain line above and Slow the crack. However, licensee management rejected these plans in t b interest of personnel safet On June 26, 1990, the licensee reduced reactor power, removed the turbine 'com service, and cut out and replaced the affected section of piping. The 11.ensee found that the pipe wall downstream of the orifice had suffered significa1t pipe wall thinning due to erosion. This same section of piping had failsd due to erosion approximately 5 years ago. As a result of this failure, the licensee's pipe thinning program was modified to. identify and check any addition.1 small bore piping with similar physical configurations. To da u , no additional se:tions of 3/4-inch piping in similar configurations have shown evidence of significant erosion when tested ultrasonicall .

The inspectors noted that the licensee's decision to make repairs after removing the turbine from service was a conservative and safety conscious approach to operation. The forced outage was also well planned and coordinated and all maintenance performed was successfu The inspector noted that the licensee did not process a CR to track the resolution of this event. The inspector is concerned that although the CR system would not require an entry for a balance-of-plant (BOP) event, such as this one, the potential exists for significans issues that occur on B0P equipment to not be tracked adequately,

, 3.4 Dropped Control Rod on Unit 1 l

At 1:40 a.m. on June 16, 1990, during the performance of control rod exercising per Procedure 1105.09, " Control Rod Drive (CRD) Operations " Control Rod 4 in Group 2 dropped into the core. The control board operator immediately returned the integrated control system (ICS) to the automatic mode, and the ICS system reduced plant power to 35 perecnt. The plant response to the dropped rod was ,

as designed and operator action to reduce the reactor coolant system (RCS)

pressure transient by initiating pressurizer spray was timely. Operator actions to verify shutdown margin and monitor core parameters after the transient were performed, as required. The cause of the dropped rod was determined to be a blown power supply fuse on the A-A phase of the control rod drive motor. The licensee verified that the motor was not electrically

-

.o o a

~7-faulted, replaced the fuse, and returned the rod to its normal position at 3:03 a.m. on June 16, 199 The licensee issued CR 1-90-213 to track- the assessment of this event and to assign any corrective actions resulting from that assessment. The licensee's root cause evaluation revealed that the high instance of fuse failures on B&W CRD motors had been researched indepth by Duke Power and its subcontractor At Duke Power's Oconee units, the high rate of failure was determined to be caused by fatigued fuse elements which were the direct result of the cycled '

sharp de current. As a result of this finding, Duke Power instituted a routine i replacement of.all CRD motor fuses at 12-month intervals and a program to test new fuses prior to installatio ;

Based on the above information, the licensee instituted actions to initiate a testing program for replacement fuses and plans to change out all fuses during i the upcoming outage in October 1990,

^ OPERATIONAL SAFETY VERIFICATION (UNITS 1 AND 2) (71707)

The inspectors routinely toured the facility during normal and backshift hours to assess general plant and equipment conditions, housekeeping, and adherence to fire protection, security, and radiological control measures. Ongoing work activities were monitored to verify that they were being conducted in accordance with approved administrative technical procedures and that proper communications with the control room staff had been established. The inspectors observed valve, instrument, and electrical equipment lineups in the field to ensure that they were consistent with system operability requirements and operating procedure During tours of the control room, the inspectors verified proper staffing, access control, and operator attentiveness. Adherence to procedures and limiting conditions for operations were evaluated. The inspectors examined equipment lineup and operability, instrument traces, and status of control room annunciators. Various control room logs and other available licensee documentation were reviewe . MONTHLY SURVEILLANCE OBSERV4 TION (UNITS 1 AND 2) (61726)

The inspector observed the TS-regtired surveillance testing on the various components listed below and ver% t testing was performed in accordance with adequate procedures, test instrumen ition was calibrated, limiting conditions for operation were met, removal and =storaticn of the affected components were accomplished, test results conformed w.1 TS and procedure requirements, test results were reviewed by personnel other Nan the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The inspector witnessed portions of the following test activities:

.

. _ .

0 ..

'

.

8-

Channel functional test of the logarithmic power instrumentation features (Procedure 2304.040). TS 4.3.1.1.1 requires that a channel functional test of the log power instrumentation be performed prior to a plant startup. While the plant wu shut down in March 1990, the licensee identified ', hat previous functional tests of the log power instrumentation had not fulfilled TS reqyirements. Specifically, the previous test verified proper log power indication, but did not verify the correct bistable setpoints for the high log power alarms and trip functions. To resolve the issue prior to plant startup in March 1990, applicable portions of the instrumentation and control (I&C) procedures that test the log power indication, alarms, and trip setpoints were performe While observing the log power functional test on June 29,1990 (prior to

' plant startup), the inspector noted that only the high log power alarm and trip setpoint were tested. When questioned by the inspector, an I&C technician stated that an earlier review of the log power TS surveillance -

by the licensee's surveillance group had determined that a test of the alarm and trip setpoints satisfied the TS requirement. After further review, the inspector learned that the log power indication test checked the log power circuitry by inputing test signals at the excore preamplifier and then verified correct meter indication, while the log power alarm and trip test only verified the applicable bistable setpoint by inputing a test signal into the bistabl The TS definition for a channel functional test requires the injection of a simulated signal into the channel as close to the sensor as practical to verify operabilit Failure to perform an adequate surveillance on the logarithmic power instrumentation is a violation (368/9019-01).

l The licensee . H ew of the log power indication during startup verifiod l that the log power instrumentation was operable even though the

!

surveillance test was not adequately performed prior to the startu Since this event did not involve a missed surveillance due to inadequate I control of scheduling, as has occurred in the past, it is not another i example of previously missed TS surveillance However, the inspector was concerned that the licensee's decision to perform only a portion of the surveillance was partially based on inaccurate information and resulted in a nonconservative determinatio *

Monthly surveillance test of Emergency Diesel Generator (EDG) 2K-4A (Procedure 2104,3b, Supplement 1). Prior to the EDG test run, air is bled off of each air accumulator in the EDG air start system to allow starting and checking of the air compressors. The bleeding off of the air also drains any moisture from the accumulato Based on the amount of water drained from the accumulator (greater than 1 quart), the inspector questioned the licensee if the monthly draining of water was adequate for

.

moisture control in the EDG air start system. The inspector noted that l

for Unit 1 EDG air accumulators, the water is drained every shift.

i h

. *O

,

. After sampling and measuring the water drained from the accumulators for both Unit 2 EDGs, the licensee estimated that the accumulated amount of water over a 1-month period would be approximately 1 1/2 quarts. The inspector was informed that the practice of draining the water from the-Unit I accumulators every shift resulted from moisture problems in the air compressors which are a different type from the Unit 2 compressors. Based on repeatability of the 1 1/2 quart estimate, the configuration of accumulator inlet and outlet piping, and a lack of previous moisture problems in the air start system, the licensee concluded that monthly draining of the water was adequate. The licensee was thorough and responsive in resolving the inspector's concerns of moisture in the EDG air start syste *

Quarterly test of the Loop "A" Higt essure Injection (HPI)

Valves CV-1219 and CV-1220 (Procedure 1104.02, Supplement 1). In addition to demonstrating the operability of the two HPI motor-operated valves, the test also verified that the downstream check valves had only nominal backleakag *

Monthly test of Channel "B" of the Unit 2 plant protection system (Procedure 2304.38, Job Order 816781). The inspector observed portions of the test involving the trip circuit breaker and the engineered safeguards feature matrix testin . MONTHLY MAINTENANCE OBSERVATION (UNITS 1 AND 2) (62703) ,

6.1 Station Maintenance Activities 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 j standards and in conformance with the T ;

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, and radiological and fire prevention controls were implemented. Work requests were reviewed to determine the status of j outstanding jobs and to ensure that priority was assigned to safety-related l equipment maintenance that may affect system performanc The following maintenance activities were observed:

!

'

Overhaul and MOVATS testing of Limitorque operator for "A" Service Water i Bay Sluice Gate 2CV-1471 (Procedure 1403.40, Job Order 778523). In addition, Plant Change 89-0047 was performed which installed a bypass in the torque switch circuitry to allow bypass of the torcue switch for 20-25 percent of gate movemen ,

,

.. *

'

.

-10-

• Calibration and string check of Pressure Transmitter 2PT-5108 for the HPI (Procedure 2304.001, Job Order 217042). While evaluating NRC Bulletin 90-01, which addressed the loss of fill-oil in transmitters manufactured by Rosemount, the licensee identified higher than normal drif t for Transmitter 2PT-5108. As part of the bulletin followup program, the licensee performed an additional calibration for those transmitters that had previously exhibited drift in the calibratio During the recent ;

test of Transmitter 2PT-5108, the transmitter response time was normal and the calibration drift limits were within the procedural limit '

Replacement of the desiccant in the Unit 2 Instrument Air (IA) Dryer 2M-70 (Job Order 847634). The licensee initiated CR 2-90-025 following a review of recent IA system surveillance results which indicated dew point ,

temperatures between -10 and O'F. The safety analysis report (SAR)

requires a dew point temperature of -40'F for air exiting the IA dryer, The licensee's evaluation of the recent IA moistore content (versus the values given in the SAR) stated that the systems and components served by the IA system had not been adversely affected, This was based on no recent equipment failures caused by moisture in the IA system and recent industry information on IA system parameters and operational informatio The licensee's review of the dryer maintenance history identified that incorrect temperature setpoints, incorrect purge flow rates, and incorrect timer setpoints have been made. Maintenance was performed to reestablish the original setpoints and flow rates. After these changes, replacement of the desiccant, and several other minor adjustments, the dew point temperatures have been in the -35'F range. The licensee is continuing to monitor the dryer's performance and is also evaluating the performance of the Unit 1 IA syste *

Replacement of the fuse and indication light for the transfer switch associated with 125-Vdc Distribution Panel D21. Earlier, an operator j attempted to replace the indication light bulb; however, the bulb broke l

and the resulting electrical short blew the fus Since the licensee was

,

unable to obtain a " qualified" replacement fuse, a commercial grade fuse l was upgraded for this application. Part of the dedication process involved performing destructive tests on fuses from the same manufacturing i lo * Repair of Containment Isolation Valve 2SV-5893 in the RCS sample line.

!

When operators attempted to close the solenoid-operated valve following an RCS sample, flow through the valve continued. The operators then closed the inboard Containment Isolation Valve 2SV-5833 to secure the flo TS 3.6.3.1 was then entered, which required the closing and deactivation of Valve 2SV-5833.

,

Attempts to close Valve 2SV-5893 by cycling and backflushing the valve were unsuccessful. The valve was disassembled for repairs. No obvious defects were evident. The valve internals were cleaned and the disc and pilot assembly was replaced. After reassembly, the local leak rate

-

i

, e j

'

- j-11-

,

l test (LLRT) indicated excessive leakage through the valve. A limited design change was then performed to replace the 1/2-inch Target Rock valve with a 1-inch Target Rock valve. However, the LLRT for the new valve was unsuccessful. A vendor technician was brought on site for additional guidance, Af ter several repair attempts, the new valve passed the LLR While the overall effort to correct the leakage was well supported by the licensee, the lengthy repair time and the large number of repair attempts indicated a lack of technical and repair knowledge by the licensee for Target Rock valves. The licensee was pursuing additional training of plant personnel on the repair methods and operating characteristics of Target Rock solenoid-operated valve .2 EDG Outage On June 6, 1990, the Unit 2 EDC 2K-dA was taken out of service for a 1-day outage. The following maintenance activities were observed: ,

• Replacement of Level Switch 2LS-2834 in the jacket water expansion tank for the EDG (Plant Change 90-8026, Job Order 813763). With installation of the new design level switch, the temporary modification (TM), installed after failure of the old level switch, was removed. The TM had been ',

installed to prevent the level switch from causing a ground in the 125-Vdc power supply system.

l *

Repair of several small fuel oil leak '

l Inspection of the bearing end caps for the lower piston connecting rods.

t During previous work on the upper bearing end caps, the licensee identified that some of these caps were installed at the wrong location All the lower caps were in their correct locatio Testing five ITE time-delay relays (Procedure 2403.007, Supplement 7).

While checking the time-delay setpoints for the relays during the last refueling outage, the setpoints had drifted outside the allowable tolerance. As part of the corrective action, the licensee changed the testing frequency from 18 to 9 month Two of the relays (T-3A and T-3B) are critical to EDG operation since they bypass the low lube oil pressure trip feature during the first '.5 seconds of EDG operation. During the recent test, Relay T-3A and anotner relay were slightly outside the time setpoint tolerance. Both relays vere reset, An additional test was performed during each monthly EDG !urveillance when the operators used a stopwatch to measure the bypass titie of the low lube oil trip feature. The licensee has determined that the rionthly check of the relay setpoint is sufficient l

to detect any future dri't of the relay that could affect EDG operabilit A design change has been developed and is scheduled for installation during the next refueling outage (February 1991), which will install new solid-state relay '

Replacement of a fuel oil pum , .

.

-12-The overall maintenance effort during the EDG outage was well planned and good 4 coordination between the various crafts (mechanical, electrical, and I&C)

allowed the completir,n of a large work package in the 1-day outag .3 Repair of a Leak in the Service Water (SW) Piping The licensee discovered a pinhole leak in a carbon steel 4 x 2-inch reducer located in the SW outlet line from the Emeisency Control Room Chiller .

Condenser 2VE-1A. The leak was discovered on May 1,1990, and a job request was written to initiate repair of the lea On June 7, 1990, the reducer was replaced (Job Order 813196). The licensee retained the O d reducer for_a failure analysis and the root cause determination of the pinhole lea The inspector was not aware of the pinhole leak until the repair was started on June 7, 1990. After questioning the licensee, the inspector was informed that a CR had not been written when the leak was discovered. Later, after questioning by the inspector, CR 2-90-243 was written to document the lea Paragraph 16.2.3 of the Quality Assurance Manual, Operations states, in part, that, " Evaluation of the corrective action is to be performed by the individual / group identified within approved procedures to determine its adequacy and completeness and to assure the need for additional corrective action . . . ." At ANO, for system deficiencies such as a leak in a safety-related pipe, the CR process is used for the evaluation of the corrective action, in additinn, the CR process is the formalized method for making an operability determination of a deficient conditio Since a CR was not written when the pinhole leak was first discovered, an operability determination with the proper reviews was not performed. Failure to initiate a CR when the pinhole leak was discovered in the SW piping is a violation (368/9019-02).

The immediate corrective action which involved replacement of the reducer was completed on June 7, 1990, at the same time CR 2-90-243 was writte Additional corrective actions that have been completed or are being tracked by the CR involve:

• A review of outstanding Unit 2 job orders to determine if a CR should be written for a previously identified deficienc No CRs were issued as a result of this revie *

Failure analysis of the old reducer to determine the cause of the pinhole leak. This information will then be factored into the SW improvement program to determine if similar installations will require corrective actio .0 INSTALLATION AND TESTING OF MODIFICATION (UNITS 1 AND 2) (37828)

The inspector reviewed the licensee's proposed design for a temporary containment equipment hatch for Unit 1. The temporary hatch would allow refueling activities to continue in parallel with other outage activities that

. ->  !

'

.

-13-require hoses and cables to be run into containment from outside, thus significantly reducing outage duratio Unit 1 TS 3.8.6 requires that the containment equipment hatch be maintained shut while refueling operations are in progress and be held in place and secured with a minimum of four bolts. Because the design requirements imposed on the equipment hatch are significantly different for a refueling accident, ,

where the hatch acts only as a barrier to fission product release and not a pressure boundary as in a design-based accident at power, the licensee has concluded that the temporary hatch meets the intent of the TS during refueling operations. There were discussions between the resident inspector, Region IV -

project management and NRR project management regarding the licensee's approac It was concluded that, since the TS does not describe the equipment hatch, the licensee could, under 10 CFR 50.59, modify the FSAR description of the equipment hatch used during refueling mode operation The resident inspector reviewed the hatch design package and the operational constraints which were included as part of a proposed 10 CFR 50.59 change to the facility. The temporary hatch will be designed, fabricated, and tested to the requirements of Section VIII of the ASME Code, 1989 Edition, and ANSI 63 l Code, with minor exceptions to Section VIII requirements. The temporary hatch has been designed to withstand a differential pressure (dp) of 3 psid, which is well above any possible dp during refueling operations and will make provisions for hoses and cables to pass through while maintaining a seal against fission product leakag The proposed 10 CFR 50.59 change concludes that the change '

does not constitute an unanswered safety question or change to the TS. The change appears consistant with the NRC staff discussion on this issue as described in the above paragrap Generic Letter (GL) 88-17 imposes requirements on licensees when the RCS is operated in a reduced inventory configuration. To comply with GL 88-17 .'

requirements to restore containment integrity within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the licensee plans to modify the plant procedures for reduced inventory to require that the temporary hatch be removed and the permanent equipment' hatch be installed in less than 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> . ONSITE MEETING WITH LICENSEE MANAGEMENT -

On June 25, 1990, members of NRC Region IV management met with licensee

' management onsite to discuss the results of Region IV's second quarter assessment of licensee performance. An outline of that meeting is provided as Appendix C to this inspection repor . EXIT INTERVIEW The inspectors met with Mr. N. S. Carns, Director, Nuclear Operations, and other members of the licensee staff on July 25, 1990. The attendees are listed

.

'

in paragraph I of this report. At this meeting, the inspectors summarized the scope of the inspection and the findings. The licensee did not identify as proprietary, any of the material provided to, or reviewed by, the inspectors during this inspectio . .

j

-

.

APPENDIX C MIDCYCLE QUARTERLY PLANT PERFORMANCE REVIEW !

OUTLINE ANO UNITS 1 AND 2 I

PLANT OPERATIONS UNIT I NUMBER OF CHANGES OPERATIONS MANAGER ,

STAFFING INCREASE AUTHORIZED SHIFT ENGINEER ROLE OPERABILITY DETERMINATION  ;

ADMINISTRATIVE WORK LOAD ON SHIFT SUPERVISOR ,

.

FIRST QUARTER PERSONNEL ERROR RATE VERIFICATION POSITIVE ACCEPTANCE ENGINEERING SUPPORT l OPERABILITY FEEDBACK '

l COMMUNICATIONS MAINTENANCE INPUT BY OPERATIONS '

FURCED OUTAGE SCHEDULES REPAIR SCHEDULES l

PRIORITIES LICENSED AND NONLICENSED OPERATORS ERRORS LATE-1989 ATTITUDE AND MORALE PLANT OPERATIONS UNIT 2

!

MANAGEMENT CHANGES IN OPERATING PHILOSOPHY SELF-CRITICAL IDENTIFICATION OF PERFORMANCE AND EQUIPMENT ISSUES

,

,

_ _ _ _ _ _ _ _ !

- D

.

-2- i i

'

CONTROL ROOM CONDUCT MORE FORMAL AND STRUCTURED PROGRAMS FOR TRACKING OF LCOs AND EQUIPMENT STATUS OPERABILITY EVALVATIONS OPERATIONS INTERFACE DAILY MAINTENANCE PLANNING AND PRIORITIZATION HANDLING OF HIGH IMPACT ITEMS OPERATOR PERFORMANCE ATTENTION TO DETAIL SUPPORT FOR MANAGEMENT SUPPORT FOR OPERATORS FUNCTIONAL CHANGES AND STAFFING LEVELS E0P TEAM INSPECTIONS RESULTS OPERATOR LICENSING TRAINING

MAINTENANCE AMD SURVEILLANCE 4 UNITIZATION OF BOTH ACTIVITIES

MAINTENANCE PRIORITIZATION AND ACCOUNTABILITY TRACKING BACKLOG REDUCTION ATTENTION TO HIGH IMPACT ITEMS TRACKING AND TRENDING IN EARLY STAGES STAFFING OF SYSTEM AND MAINTENANCE ENGINEERS I REPETITIVE CORRECTIVE MAINTENANCE l

NUMBER OF LONG-TERM PROBLEMS SCHEDULES FOR 1R9 UNIT 1 - FIXED 7-DAY SCHEDULE

UNIT 2 - 5-DAY ROLLING SCHEDULE MODE DEPENDENT OUTAGE 3CHEDULES PLANNING AND EXECUTION OF HIGH IMPACT JOBS

!

!

/

. o  !

.

,

-

I SURVEILLANCE ADMINISTRATION MISSED SURVEILLANCES INADEQUATE PROCEDURES FORMATION OF CENTRAL TEST GROUP EMERGENCY PREPAREDNESS NUMBER OF WEAKNESSES DURING DRILL MANAGEMENT MEETING BEING SCHEDULED RECENT INSPECTION '

SECURITY PERIMETER DETECTION SYSTEM UPGRADE COMPENSATING MEASURES PERFORMANCE GENERALLY GOOD RADIOLOGICAL CONTROLS WORKER ACCOUNTABILITY EVIDENCE OF MANAGEMENT ATTENTION WEAKNESSES IDENTIFIED i

ENGINEERING AND TECHNICAL SUPPORT INTERFACES BETWEEN PLANT STAFF AND DESIGN ENGINEERING

'

COMPLETION OF STAFFING AND TRAINING SYSTEM ENGINEERS SHIFT ENGINEERS j MAINTENANCE ENGINEERS PLANT STAFF UTILIZATION OF THESE ORGANIZATIONS '

MORALE OF ENGINEERING STAFF AS RESULT OF MOVE TO THE SITE j NDE VAN CONCERNS WITH DRAWING CONTROL

..>

.

!

-

4- j l

i l

i SAFETY ASSESSMENT / QUALITY VERIFICATION i IDENTIFICATION - ANALYSIS - CORRECTIVE ACTION SELF-ASSESSMENT AND ROOT CAUSE ANALYSIS i

NUMBER OF OUTSIDE PERSONS FILLING KEY POSITIONS COMMUNICATIONS IMPROVEMENT CONDITION REPORTING ASSIGNING SIGNIFICANCE TIMELINESS OF CORRECTIVE ACTION IMPLEMENTATION INHOUSE EVENTS EVENT ANALYSIS GROUP PROBLEM TRENDING CORRECTIVE ANALYSIS REVIEW BOARD LICENSEE EVENT REPORTS TIMELINESS AND TECHNICAL CONTENT ROOT CAUSE ANALYSIS CORRECTIVE ACTIONS TRACKING OF COMMITMENTS MANAGEMENT OVERSIGHT BUSINESS PLAN FOCUS MANAGEMENT ATTENTION EFFECTIVENESS MEASURES

,

I

i

~

l

'

.

F y - Y