IR 05000338/1990018

Insp Repts 50-338/90-18 & 50-339/90-18 on 900718-0818. Violations Noted.Major Areas Inspected:Operations,Maint, Surveillances,Operational Event Followup,Mods,Self Assessment Capabilities & LER Followup

ML20059K810
Person / Time
Site:	North Anna
Issue date:	09/11/1990
From:	Frederickson P, King L, Lesser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20059K795	List: IR 05000338/1990018 ML20059K794 ML20059K804
References
50-338-90-18, 50-339-90-18, NUDOCS 9009240259
Download: ML20059K810 (15)

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Report Nos.: 50-338/90-18 and 50-339/90-18 Licensee: Virginia Electric & 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

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Inspection Conducted: July 18, 1990 through August 18, 1990.

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Inspectors:

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enior fes; dent inspector Da'te Signed Y

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,4rp ydent inspectur Dat Signed

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Approved by: U pM4

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P. E. Fredrickson, Section Chief

' I>a te 'Si g n ed Division of Reactor Projects SUMMARY

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Scope:

This routine inspection by the resident inspectors involved the following areas:

operations, maintenance, surveillances, operational event followup, modifications, self assessment capabilities, licensee event, report followup, and action on previous inspection findings.

Backshift inspections were conducted on: July 19, 24, 25, 29 and August 2.

Results:

Within the areas inspected, one violation, three non-cited violations and two strengtns were identified. One violation involved the f ailure of maintenance i

. procedures to control the removal of charging pump cubicle blocks that provide t

a radiological shield and a fire barrier.

The blocks were removed while the

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pump was operable and without compensatory measures (paragraph 3.b).

A non-cited violation involved the failure to conduct surveillances of pressurizer level response times following a TS amendment which required the

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times to be verified as a condition of operability (paragraph 6.c).

Two additional non-cited violations involved incorrect RWST level retpoint

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calibrations and missed surveillances of the AFW system (paragraph 9).

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~1 The lice.avb act sns following a. partial loss of of f site power : were...

monitored. Operator and management response was noted to be appropriate and

' conservative 1 The replacement of the faulted transformer was well executed (paragraph 4.a).

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' Management. actions were also noted to be conservative'when power was reduced on Unit 2 in response to an increasing trend on primary.to secondary leakage,

although not required.by TS (paragraph 3.a).

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REPORT DETAILS 1.

Persons Contacted Licensee Employees M. Bowling, Assistant Station Manager

"R. Enfinger, Assistant Station Manager D. Heacock, Superintendent, Engineering

• G. Kane, Station Manager P. Kemp, Supervisor, Licensing W.'Matthews, Superintendent, Maintenance A. Parker, Supervisor, Maintenance Engineering D. Roberts, Supervisor, Nuclear Safety Engineering

• J. Smith,- Manager, Quality Assurance A. Stafford, Superintendent, Health Physics

• J. Stall, Superintendent, Operations Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.

NRC Resident Inspectors L. King,_ Resident Inspector

"M. Lesser, Senior Resident Inspector

" Attended exit interview

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Acronyms and initialisms used throughout this report are listed in the last paragraph, 2.

Plant Stat'us Unit 1 operated the entire reporting period at or about 100% power and comoleted the period at day 206 of continuous operation on line.

On August 7, the. inspector participated in the licensee's annual full scale

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emergency planning exercise.

The exercise was also observed by regionC NRC inspectors.

Unit 2 operated in coastdown mode, initially at 85% power. On August 2, a fault in the "B" RSST resulted in a loss of offsite power to the 2F emergency bus. The 2H EDG started and loaded as designed (paragraph 4.4 ).

On August 13, power was reduced to 50% when increased primary to seconstary i

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leakage was detected on the "B" SG (paragraph 3.a,.

On August 14, Unit 2 broke the Westinghouse nuclear plant record for continuous days on line;

'the previous record was 463 days. The unit ended the inspection period at 50% power, day 467 of continuous operation online.

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-Operational _ Safety Verification (71707)

The inspectors conducted. frequent visits to the control room to verify

. proper staffing, operater attentiveness,and adherence to approved procedures...The~ inspectors attended plant status meetings and reviewed

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operator logs on a daily-basis to verify operational safety and compliance

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. maintain awareness of the overall operation of the facility.

Instrumentation and ECCS lineups were periodically reviewed

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-from control room indications to assess operability. Frequent plant tours l

Lwere conducted to observe equipmee status, fire protection programs,.

radiological work. practices, plant s.curity programs and housekeeping.

.l Deviation = Reports were reviewed to assure that' potential safety concerns I

were properly addressed and reported.

Selected reports were followed to ensure. that appropriate management attention and corrective actions were applied.

l a.

SG wg ' eakage

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.censee closely monitored its.SG tube. leakage rates by use of N-16 monitors on each SG, a combined MS N-16 monitor, blowdown and

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air ejector monitors and grab samples.

An increasing trend was

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ebserved on the Unit 1

"A" SG,. from about-2 gpd in April 1990 to 5 gpd as of August 12. The Unit 2 "B" SG had been indicating about 1

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.gpd leakage since June 1990. On the-morning of August 13~the Unit 2 MS header N-16 monitor alarmed at 40 gpd. The "A" and "C" individual N-16 monitors indicated less than 1 gpd but the "B" N-16 monitor read 4 gpd.

The licensee was concerned with the lack of correlation between the sum of: the individual monitors with the MS header monitor. Experience had shown; good correlation between grab samples and the individual monitors but never with the MS header monitor. At S

2:07 pm the "B" N-16 monitor spiked to 25 gpd and the MS header N-16 monitor spiked to 140 gpd. Operators also observed increased counts on the air ejector and blowdown radiation monitors.

Unit 2 was at 69% power at the time.

G The' licensee's TS allow primary to secondary leakage of up to 100 gpd on any individual SG and a total of 300 gpd above 50's power. A power

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reduction to. below 50% is required if a 60 gpd increase-is observed between 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> surveillances.

Below 60%, 500 gpd is allowed.

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2:25 pm, an air ejector grab sample indicated 29 gpd leakage. Based

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u;.on the available indications the licensee concluded that the MS u

header N-16 monitor had a significant diverging calibration error and that the actual leak in the "B" SG was on the order of 25-30 gpd and no actions would be required by the TS. As a precautionary measure, station management conservatively directed the unit be ramped down to

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below 50% power. The unit was stabilized at 49% at 3:32 pm. During

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the power reduction, the leakage rate was observed to decrease to values of 1-3 gpd nowever by August 18 it had increased to 8 gpd.

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The licensee reviewed calculations for calibration of the MS heMer l

monitor and identified mome conservative assumptions which covN N eliminated to obtain better correlation with' the sum of tb y'

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-1'dividual monitors.

The licensee. concluded however that t h =:

n accuracy - of the MS header monitor will not be as good as the

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individual monitors at. powers less than 100% due to the physicsi

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location of the detector and differences in steam piping layout.

The licensee reviewed previous eddy current test data for the SG~and

"p did ' not identify any indications that had not been adequately-

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addressed.

b.

High Head Safety Injection Pump Cubicle' Block Removal

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On August 8,-1990 operations personnel discovered the concrete wall blocks for the HHSI pump, 1-CH-P-1B, cubicle had been removed without

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proper authorization. The wall removal was in preparation to perform maintenance on the charging pump seal; however; the pump had not yet

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been declared inoperable and tagged out.

The block removal was not t

addressed in the work ~ order or the maintenance procedure.

The functions of the blocks are to act as a fire' barrier between safety related equipment and as a radiological shield,

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L Previous concerns with controls over blocks were raised in Inspection Repo rt.- 338,339/90-15, associated with service water pump structure

i missile shield blocks and resulted in a non-cited violation for inadequate contro'ls over ~ safety related structures.

The licensee stated in LER 338/90-07 that interim instructions for the Operations

. group to maintain controls over blocks had been issued until a formal

i evaluation is complete.

Copies of' the instruction were al_so forwarded to-other groups such as maintenance and construction. The

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instructions were not effective in preventing recurrence as = the j

Ks blocks' were removed as a part -of the maintenance prestaging.

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removal of the blocks did not directly. affect charging pump l'

operability however the radiological and fire barrier was breached without compensatory measures.

The duration of the event was

'approximately.two hours, reducing the level of significance, In that

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maintenance procedures failed to adequately control the removal to the_ chargi.ng pump cubicle blocks, this is identified as a biolation of TS 6.8.1, 338/90-18-01:

Inadequate Maintenance Procedures for.

Control of Charging Pump Cubicle Block Removal,

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New Fuel Receipt.

On August 1, the inspector witnessed the receipt of new fuel for Unit

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2.. Procedure 1-0P-4.2, " Receipt and Storage of New Fuel" was used.

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No problems were identified.

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One violation was identified.

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Follow-up of OperationallEvents (92703)-

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On August 2,1990, at 2:20 a.m., Unit 2 suf fered a partial loss of offsite

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power w5en the incoming breaker to the B RSST tripped open on differential-

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-lockotc due to an apparent transformer fault. At the time of the event, Unit 'l was fat 100% power and Unit 2 at 75%.

Power was lost to.the 2H emergency 4160 volt bus and the 1G 4160 volt bus.

The 2H EDG automatically started and loaded onto the 2H bus as designed.

A fast transfer ~ of the IG bus to the 2G bus via the bus tie breaker occurred as

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designed, averting a loss of power to the Unit 1 main circulating water pumps.

Both units remained at power following the transient.

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Operators used Abnormal Procedure 1-Ap-10.1, Loss of Electrical Power, to determine the extent of the power loss and to recover from the transient, t

.The standby main feedwater pump automatically started due to low feedwater:

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pressure when the feedwater heater high level divert valves opened-upon i

loss of power.. Control of the valves was regained when power was restored and the operators secured the pump.

Individual rod position indicators

momentarily de-energized, indicating control rods on the bottom; however, _

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they immediately returned to: correct indication.

The Safety Parameter

Display System failed due to the transient and was restored to service by 4:00 a.m.

No other equipment problems occurred.

.,a Dedicated operators'and mechanics were assigned to monitor the 2H EDG and

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take hourly ' logs.

As an additional conservative measure, the licensee

postponed unnecessary activities which potentially. posed challenges to the

system.

The licensee ~ applied the-72 hour action statement of TS

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3.8.1.1.'a, which required verifying operability of the remaining RSST by correct breaker alignment within 1 -hour and every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereaf ter and-l toLtest the 2J EDG within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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The licensee was able to replace the RSST with a spare transformer located onsite within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time frame. The changeout was observed to be

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well executed and management actions were conservative.

During the event, the EDG. remained loaded to 1810 kW which included the operating charging pump, service water _ pump, component cooling oump,

containment and CRDM cooling fans, and pressurizer heaters. Since the EDG

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is rated at 3000 kW (3300 kW for 30 minutes) the question war raised as to the response of the EDG following an ESF actuation due to additional-loading of ECCS equipment.

The licensee addressed three cases: a design basis accident or CDA, a safety injection and a loss of offsite power.

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The design basis accident would initiate a CDA signal which would trip the containment and.CRDM fans and the component cooling pump.

Pressurizer heaters would trip on low pressurizer level.

The licensee calculated this would initially remove 917 kW, however a quench spray pump, casinn cooling oump and low head SI pump would immediately. block lusa, adding a starting load of 970 kW- (runring-load of 573 including additional power for the charging pump to supply SI flow).

The EDG would therefore supply a total of 1853 kW

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_ starting load and 1466 running load; both within its rated capacity.

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- Voltage would drop to 60% of rated voltage and recover within '10.

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seconds.1 The first block load is the worst case and additional.

sequencing of other loads such as AFW, and recirculation' spray pumps

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occur 'following-voltage and frequency recovery.

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If-a safety injection signal were to occur, no load shedding would take place and the initial block loading would include the low head

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SI pump, the high head SI pump and a. service water pump..During the l

event', the high head and service water pumps were running off: the.

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. EDG, therefore the low Head SI pump starting ' load.of 433 kW would t

require the EDG to initially supply 2243 kW. The AFW pump would

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start 20 seconds later and the EDG would supply a total starting load

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of 2609.

'If the HHSI and service water pumps cn that bus were not already

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running, the starting load combined with that of the LHSI pump would

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momentarily overload-the diesel at 3339 kW. It should be noted that this situation could occur during an accident scenario in which offsite pnwer was lost sequentially.

The licensee provided the.

inspector with an analysis which. showed the diesel could withstand momentary overloads up to 3681 kW, At the end of the' inspection period, review of the ana' lysis and overcurrent relay trip settings-was not complete. Pending completion of the review by the inspector and-implementation of administrative controls by the licensee to reduce accident starting loads of the EDG, this is identified as L

Inspector Followup Item 339/90-18-02:. Review of EDG Loading-During

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. Loss of Offsite. Power Followed by Postulated Accident. Scenario.

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If a loss of offsite power occurred on! the J bus, and the

"C"

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charging pump was in standby being powered from the H bus, the. pump would start, causing both the

"A" and

"C" charging pumps to be

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' supplied from the-H EDG. Since the starting load on a charging pump-is 1338 kW, the overload rating would be approached but not exceeded.

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During the event the

"C" charging pump was in " pull to lock" for a

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maintenance.

Administrative controls are also being evaluated to minimize the challenge to the EDG from the start of a second charging-pump.

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The inspectors t lentified one area of concern associated with

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restoration of certain. loads.

Abnormal Procedure 1-AP-10.7, Restoration -of 2H 4160 emergency bus, does not provide short-term actions for operators to manually restore loads such as boric acid storage. tank heaters and pressurizer heaters. The operators were

aware that the loads needed to be restored and relied upon other

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sources (not referred to in the AP) for an accurate listing of loads.

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The inspectors also pointed out several errors in the electrical

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distribution graphics attached as enclosures to the procedure associated with circuit breaker designation. The licensee initiated

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l action to review the adequacy of the procedure.

The licensee is a

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currently upgrading the abnormal procedures and. completion of-the effort is-scheduled-for_the first' quarter of 1991.

No violations or devia' tion were identified.

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Vaintenance Observation (62703)

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. Station maintenance activities 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

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TS requirements.

The Unit :11 and Unit 2 gas strippers have been inoperable for several

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months due primarily to steam being isolated for various maintenance activities.

The purpose of the gas strippers are to remove entrained and dissolved gases from reactor coolant sources such as the primary drains

x transfer tank. During normal operation, steam heats the liquid, which causes the radioactive gases to be -stripped and routed - to the vent condensers, compressed and processed by the waste gas system. The liquid

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is pumped to the boron recovery tanks.

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'The inspector raised-concerns regarding the ineffectiveness of removing j

radioactive gases from the liquid with steam for the gas stripper isolated

ana the consequences of the gases remaining entrained in the liquid and

sto' red in.the boron recovery tanks.

Under normal operation the boron-recovery tanks are under a slight negative pressure due to the process vent system, however the potential may exist for venting the tank to atmosphere. Since the tanks are not seismically designed, a tank rupture

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may be postulated resulting in an unmonitored release.

i The North Anna ~ UFSAR states in section -11,3.5.2 "All of the noble gases are stripped from the boron recovery letdown in the gas stripper prior to-entering the boron recovery tank and are not available for release from

the boron recovery tanks". The inspector informed the licensee that the

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gas stripper was not being operated as described in the UFSAR, apparently due'to long-standing maintenance issues. The licensee had not performed a safety evaluation in accordance with 10 CFR 50.59, but did inform the j

inspectors that one would be conducted.

Pending evaluation of the.

significance of entrained gas in the boron recovery tanks, this in identified as Unresolved Item 338/90-18-03:

Gas Stripper Inoperability and Potential for Unmonitored Releases.

No violations or deviations were identified.

6.

Surveillance rbservation (61726)

The inspectors observed / reviewed TS required testing and verified that testing _ was performed in accordance with adequate procedures, that test i

instrumentation was calibrated, that LCOs were met and that any deficiencies identified were properly reviewed and resolved.

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Outside Recirculation Spray Pump Test-On July 17, 1990, the inspector witnessed the test of the Unit 1 B outside' recirculation spray pump using 1-PT-64.1.3, Periodic Test of-Recirculation Spray Subsystem Pumps. The new revision 18 incorporated

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lessons. learned during the performe.nce of a previous test on June 10.

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Problems encount'ered previously included the inability to obtain a

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stable reference discharge pressure and a pressure spike upon pump l

start, An adjusted test discharge. pressure was obtained by-J

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subtracting the static suction pressure, af ter the pump was secured, from the final ~ operating discharge pressure.

This compensated for the rise in pressure caused by the heating of the fluid due to the.

pump running in the recirculation mode for five minutes. The Unit I crecirculation pumps have no high point vents which could account for the discharge-pressure surge typically observed when the pump-- is _

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first started. A recorder connected to the discharge pressure showed that the pressure spiked to 220 psig on start.

The expansion 1 joint

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on the. discharge piping is rated at 185-psig. A visual inspection and-evaluation of the expansion joint showed no damage.

The test was performed satisfactorily, b.

-Control Room Bottled Air Test On July 19, the inspector witnessed 0-PT-76.4, Control Room Bottled Air Pressurization Test. The test was performed satisfactorily,

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although some problems were experienced.

1-CA-PCV-1306A, the pressure control valve for the Unit 1 bank failed to control properly during the test and at times oscillated between 40 and 110 psig.

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. trip valve automatically closes-at - 110 psig.

The Unit 2 banks, however, compensated for the erratic operation of 1-CA-PCV-1306A. At'

m the termination of the test the Unit 2 banks had bled down to under

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200 - psig and Unit 1 was still at 970.psig.

One other problem identified was that, although the solenoid operated valves HV-1306A and.HV-13068 appeared to be open, the lights on the-Unit 1.back panels did not change color and indicated closed. Work orders were 1,

written for the lights and Unit

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1-CA-PCV-1306A.

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A special test on Unit I control room bottled air pressurization was run on -July 24 to adjust the controller for 1-CA-pCV-1306A. During-the adjustment of the controller, it was discovered that the upstream

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trip valves were closed, but leaking through, thus accounting for the closed lights on the trip valve solenoids HV-1306A ' and HV-1306B.

Once the controller fas adjusted properly, the trip valve opened and the lights on HV-1306A and 1306B indicated open.

The inspector witnessed the adjustment of the valve which eliminated the hunting and allowed a constant air pressure. The inspector verified that a work order was written to repair the trip valves.

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-The control room bottled air pressurization test 0-PT-76-4 was rerun on July 25 as a post-maintenance test.

The inspector witnessed the test' and both unit control valves ope. rated properly.

The test was

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completed satisfactorily, c.

Peessurizer Level Response Time Testing On July 20, 1990, the licensee informed the inspector that response time testing on the three channels of pressurizer high level reactor trip had not been conducted.

Technical Specifications-require 3 channels of the pressurizer high level trip function to be operable with 1 2.0 second response time. Additionally, response time testing is to be performed on at least one channel every 18 months such that all channels are tested every 54 months.

The requirement :became effective on January 3,1989 for Unit I and on June 30, 1989 for Unit 2 with license amendments 112 and 100 respectively.

The Unit 2 amendment allowed 30 days for implementation.

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The amendments were required to allow for a more negative moderator temperature coefficient at core end-of-life due to longer burn-up.

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cores.

The licensee's DNBR evaluation methodology relied on the

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pressurizer level trip for certain accidents to preclude filling the pressurizer.

The licensee did not take any baseline response time testing-on the channels and interpreted tha surveillance tests due 18 months n

date-of issuance, although it was intended to conduct the testin during subsequent refueling outages.~

The licensee considered the Unit 1 surveillances on one of the three -channels to be due in approximately November 1990 (including a 25% grace period).

Since a scheduled outage, was not planned, the licensee was considering E

requesting a waiver;of compliance to defer the testing until the next outage.- The inspector informed the licensee-that the surveillances were-required to be performed on all channels upon implementation of the TS amendments and that they were currently overdue on both units.

At that point, the licensee applied TS 4.0.3, which specifies that failure to perform a surveillance constitutes non-compliance; however, application of the action statement may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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The licensee requested a temporary waiver of compliance on July 20 followed by an ' emergency TS change request on July 23 to revise effective dates for initiating response time testings to no later q

than start-up from each unit's next refueling outage. The basis for

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the waiver.was (1) an assessment of available data for similar channels (steam generator level) indicated a high degree of confidence that the total response time for the channel would be

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significantly less than 2 seconds, and (2) for current core

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conditions on both units, the safety analysis shows that no credit

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has to be taken for the pressurizer water level high reactor trip N

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f-function to mitigate the consequences of an uncontrolled rod'

withdrawal or boron dilution; event. The NRC granted the. waiter on -

July 20,.with written' followup on July 25,1990.

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.The' inspector-reviewed t h'e licensie's. evaluation of safety significance for the missed tests. The licensee concluded that the -

pressurizer overfill concern prior to automatic reactor trip is a potential concern for uncontrolled reactivity instrtion caused by rod withdrawal or. boron dilution under. all of the following plant conditions:

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- reduced power (S 60%).

- low reactivity feedback (early in core life)

-: low reactivity insertion rates (S 10 pcm/sec)

- failure of pressurizer high level trip The concern exists primarily as a result of the licensee's most -

recent analysis using the NRC approved RETRAN code and methodology, which was performed to support implementation of the licensee's

' Statistical DNBR methodology. The new methodology included a widened band of' assumptions with respect to doppler and moderator temperature feedback to increase design flexibility for subsequent reloads'. The concern did not exist during the licensee's previous analysis using

.the LOFTRAN code which applied to the current Unit-2 core early in-life. = Based on this, the inspector concluded that the event involved reduced safety significance.

Concerns were raised, however, with the licensee's program for adequately implementing.TS requirements.

Without performing the surveillance requirements in this case upon issuance of the.TS

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amendments, no basis existed to assure operability of the pressurizer level channels.

The= licensee additionally failed to perform the response time testing prior to startup following the Unit i refueling.

outage of' February 1989 as required by TS 4.0.4.

Although channel

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calibration procedures were initially flagged as potentially E

requiring revision, reorganization of the onsite engineering group

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l and the instrument maintenance group resulted in the f ailure to implement the changes.

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l The licensee's immediate response to the event included the

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I performance of in-situ time response measurements, using transmitter noise analysis techniques and direction to the Quality Assurance-

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group to evaluate TS implementation programs.

The noise analysis

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measurements resulted in transmitter response times of less than 2 seconds. This is identified as a non-cited violation 338/90-18-04, Failure ' to Conduct Pressurizer Level Response Time Testing.

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licensee identified violation is not being cited because criteria

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specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.

One non-cited violation was identified.

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Installation and Testing of Modifications (37828)-

Selected. licensee modifications were observed or-reviewed by the inspectors to verify. that work was - conducted-by qualified workers,

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approved procedures were used, drawings and procedures were' updated and systems were properly tested prior to returning' them to service. Safety evaluations conducted pursuant to 10 CFR-50.59 were reviewed to determine

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adequacy.

Portions of the following modifications were. inspected:

EWR 89-036 Instrument Air System Compressor Upgrade DCP 89-33 Diesel Generator Undervoltage Start Relay DCP 88-11-Reactor Coolant System Level' Indication

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EWR 89-196 Test Circuit for Alternate Feeder to Emergency Bus EWR 83-078 New Disc for-1-SW-MOV-103-EWR 90-51 Logic Reversal for Recirculation Spray Pump Head Tank:

Level Annunciator u

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No violations or deviations were identified.

l 8.

Evaluation of Licensee.Self Assessment Capability (40500)

The Elicensee recently -received NRC approval of TS amendments' to add

requirements for. the MSRC to provide the ~ independent review of' station activities including safety evaluations, TS changes, violations, reportable events and significant deficiencies. The M5RC is chaired by-

7 the -Vice President of Nuclear Services and contains members with sufficient qualification and expertise.

The inspector attended portions-

of the most recent MSkC meeting.on August 14. The issues reviewed by.the

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MSRC y appeared to receive appropriate. attention for evaluation of corrective action,. recurrent problems and followup of previous concerns.

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The inspector also reviewed selected activities of the onsite review j

group, Nuclear Safety Engineering.'

One HPES report was reviewed l

concerning the details surrounding inadequate controls for the service j

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water pump structure missile shield block removal (Inspection Report l

338,339/90-15). The report concluded that written policy defining control

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.of removable blocks' did not exist and provided recommendations - for

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' corrective action.

Licensee interim corrective ' actions however were not~

effective in preventing recurrence as a similar event on-the charging pump (paragraph 3.b) occurred.

No violations or deviations were identified.

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9..

-LER Followup (92700)

l 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 and that generic applicability had been considered.

Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or TS conditions had been identified.

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e (Closed) LER 338/90-05: Incorrect RWST Aut'o Switchover Level Setpoint Due

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to Procedural _ and Personne1' Error.

For approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> on April 3

'1990' the. automatic switchover setpoints of the Unit 1 RWST level instrument channels were set high and could have caused a premature swapover to the containment-sump and a questionable NPSH available for

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ECCS pumps. The calibration error was caused by an incorrect test point referenced in the procedure and an additional personnel error when connecting test equipment. The licensee corracted the procedures and now requires immediate evaluation of "as found" data when it differs from the expected value. This is identified as a non-cited violation 338/90-18-05,

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Incorrect RWST Auto Switchover Level Setpoint.

This licensee identified

violation 'is not being cited because criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.

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[2 (Closed) LER 338,339/90-10:

Missed Auxiliary Feedwater Pump, Valve, and

_ Flowrate Surveillances Due to Personnel Error. The required surveillance tests on.the AFW pumps and valves exceeded the quarterly surveillance interval by one month when the test procedure was revised and the time

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-~since the previous test was not. considered, The procedure revision also failed to ensure' channel checks on AFW flowrate were conducted monthly and incorrectly required them -to be performed quarterly since September 1989.

L No examples occurred where the missed surveillance failed to detect l'

inoperable equipment. 'The licensee performed an audit to determine.if

other tests were improperly scheduled and is_ revising its procedures for ensuring 'that tests are scheduled correctly.

This is identified as a non-cited L violation 338/90-18-06,. Missed AFW Pump, Valve and Flowrate i

Surve111ances.. This licensee identified violation is not being cited

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because < criteria specified in Section-V.G.1 of the NRC Enforcement Policy were satisfied.

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Two non-cited violations were identified.

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10. - Action on Previous Inspectip Items (92701, 92702)

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.(Closed). Violation 339/88-33-03: Overflowing Process ' Vent system and -

Contaminating Auxiliary Building Floor by using Inadequate Procedures and o

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' Unrevised Drawings:

The licensee responded to the vio.ation in correspondence dated March 3, 1989.

Corrective action.ncluded the development of a series of procedures for resin transfer addition and rinse; elimination of a generic resin procedure; training of operators;

' and - revision of administrative procedures to ensure review of all l applicable controlled documentation during operating procedure changes.

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'(Closed)

Unresolved Item 338, 339/89-26-04: Unit 2 Main Turbine

. Mechanical Overspeed Test Question. The licensee's safety evaluation to defer' overspeed testing on a one-time basis for the main turbine was reviewed by NRR (TAC 75428-T1A).

The staff determined that the ASLB

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commitment does not preclude the licensee from using 10CFR50.59 to defer the test. The staff also determined that the licensee is required to test the overspeed trip mechanism every 18 months; however, a one-time deferral is acceptable based upon the licensee's use of a Westinghouse analysis.

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The analysis indicated that there is no discernible change in the the test probability of generating destructive overspeed missiles whenThe trip mechanism is highly interval is changed from 18 to 36 months.

Since reliable and there are other redundant and diverse trips available.that com tne analysis points out degradation can have a significant effect on component failure no basis exists for a permanent change to an extended Based upon this, the staf f concluded that a one-time deferral probability, frequency.

wds 8CCeptable.

.,a8,339/88-16-01 :

Failure to Perform (Closed)

Apparent Violation A notice of violation was issued for Adequate 10 CFR 50.59 Evaluation.

this item on July 5,

1989 against, which also included additional associated with the RSHX.

The inspectors will monitor 338,339/89-08-03.

violations corrective action as followup to violation 11.

Exit (30703)

21, 1990, with The inspection scope and findings were summarized on Augustinspectors described the those persons indicated in paragraph 1.

The detail the inspection results listed inspected and discussed inThe licensee did not ident'fy as proprietary any of t areas provided to or reviewed by the inspectors during this inspection.

below.

Dissenting comments were not received from the licensee.

Descriptioj and Reference Item Number Inadequate iaintenance Procedures for Control of VIO 338/90-18-01 Charging Pump Cubicle Block Removal (paragraph 3.b)

Review of EDG Loading Following Loss of Offsite IFI 339/90-18-02 Power and Postulated Accident Scenario (paragraph 4.a)

Gas Stripper Inoperability and Potential for URI 338/90-18-03 Unmonitored Release (paragraph 5)

Failure to Conduct Pressurizer Level Response NCV 338/90-18-04 Time Testing (paragraph 6.c)

Incorrect RWST Auto Switchover Level Setpoint NCV 338/90-18-05 (paragraph 9)

Missed AFW Pump, Valve and Flowrate NCV 338/90-18-06 Surveillances (paragraph 9)

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U 12. Acronyms and_Initialisms

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AFW Auxiliary-Feedwater AP

. Abnormal Procedure

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ASLB Atomic Safety and Licensing Board CDA Containment Depressurization Actuation

'CRDM Control Rod Drive Mechanism

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CFR=

Code of Federal Regulations g'

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DCP _

Design Change Package

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DNBR-Departure from Nucleate Boiling Ratio

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ECCS Emergency Core Cooling System t

EDG Emergency Diesel Generator

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ESF Engineered Safety Feature a

EWRE Engineering Work Requests HHSI High Head Safety Injection HPES LHuman Performance Evaluation System

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GPD~

Gallons Per. Day.

IFI Inspector Follow-up Item kW-Kilowatt

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Limiting Condition for Operation LER Licensee Event Report MOV.

Motor Operated Valve l!

MS Main Steam

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MSRC-Management Safety Review Committee

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NPSH Net Positive Suction Head

.NRC Nuclear Regulatory Commission 0P Operating Drocedure PCM/SEC

' Percent Miilirho per Second

PSIG

. Pounds Per Square Inch Gauge-RSHX-Recirculation Spray Heat Exchanger RSST Reserve Station Service Transformer

WST'

Refueling Water Storage. Tank R

SG Steam Generator SI Safety : Injection

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TS Technical Specification UFSA-Updated Final Safety Analysis Report

.t URI Unresolved Item L.

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