IR 05000282/1990012

Insp Repts 50-282/90-12 & 50-306/90-12 on 900703-0813. Violations Noted.Major Areas Inspected:Plant Operational Safety,Maint,Surveillance,Regional Initiatives,Lers & Previous Insp Items

ML20059D822
Person / Time
Site:	Prairie Island
Issue date:	08/27/1990
From:	Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20059D817	List: IR 05000282/1990012 ML20059D814 ML20059D819
References
50-282-90-12, 50-306-90-12, IEIN-89-079, IEIN-89-79, NUDOCS 9009070197
Download: ML20059D822 (15)

Text

- __ _ . .

-

.

,

.

U. S. NUCLEAR REGULATORY COMMISSION 1

REGION III

Reports No. 50-282/90012(DRP);50-306/90012(DRP)

'

Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60 Licensee: Northern States Power Company 414 Nicollet Mall 1 Minneapolis, MN 55401 Facility Name: Prairie Island Nuclear Generating Plant Inspection At: Prairie Island Site, Red Wing, MN ,

Inspection Conducted: July 3 through August 13, 1990 Inspectors: P. L. Hartmann D. C. Kosloff b u. d k bMI Approved By: kB. L. Burgess, Chief d b S O 7'IO Reactor Projects Section 2A Date Inspection Summary t

i Inspection on Jul 50-306/90012(DRP)y ) 3 through August 13,1990(ReportsNo. 50-282/90012(DRP);

Areas Inspected: Routine unannounced inspection by resident impectors of 31 ant operational safety, maintenance, surveillance, regional initiatives,

.ERs, and previous inspection item Results: The plant operated at full power the majority of the inspection period. Unit I was derated to 97 percent for a short period due to LOCA analysis concern One unplanned autostart of an ESF system occurred when a component cooling pump auto-started when the pump was secured improperly. There were no autostarts duo to radiation monitor spikes, which have been a repetitive problem in the pas Of the six areas inspected, two violations and one unresolved item were identified. The unresolved item involved a radiation monitor being out of

,

service during operation of a ventilation system (paragraph 3b). The first l violation involves a personnel error which resulted in a shield building ventilation system being inoperable (paragraph 8.a). The second violation involves two examples of missed surveillance requirements caused by personnel error (paragraph 8.b).

9009070197 900827 gDR ADOCK 05000282 PDC

.

. . . . _

. .

-

.

The following additional sunnary information is provided by.SALP dunctional area: .

!

Operations Both untM operated at near full power the entire period. Historical '

repetitive vtuations from radiation monitors oa chlorine monitors did i not occur during the inspection period. A reportable auto start of a :

component cooling water pump occurred and the cause appeared to be a lack -

of training regarding the particular operation of the pump remote- ,

controller. Attention to detail problems, identified in the past, were '

not present during this period in the operations are Maintenance / Surveillance Violations involving )ersonnel error were identified in the area of surveillance during tie report period. The root causes associated with 1 these violations were attributed to personnel errcr. In addition to '

personnel error, one of the violations occurred from a non-cognitive scheduling error. The other violation involved a misur.derstanding between licensee staff regarding the need to perform the surveillance. The surveillance program does not compensate for errors in a manner that will ;

prevent exceeding timeliness requirements. Licensee management is ,

considering changes to the surveillance program in response to this concer A second example involved a missed surveillance which occurred following a change to a surveillance schedule. The surveillance coordinator communicated the r.eed to perform an additional surveillance if the surveillance was delayed due to a schedule change. However, this '

connunication was not understood by the surveillance grou A second violation was identified involving the inoperability of both +

trains of the Shield Building Ventilation System. The cause of the wrong '

train exhaust fan being taken out of service was due to a typographical ,

error on a critical equipment identifier on the work procedure. A contributing cause was personnel error since two other accurate

!

!

identifiers were present on the work procedure. The licensee is considering changes to procedures- to ensure the electrical preventive maintenance procedures involved have adequate verification steps to prevent any recurrence. - .

_ Engineering and Technical Support The licensee responded well to-issues arising in this area during the period. First, a Part 21 notification was submitted to the NRC involving an accident analysis error. The plant response was prompt and I

conservative. This action included a'3 percent derate by the licensee.of

! the Unit 2 plant when the magnitude of the error was not fully -

ascertainabl ;

.. . . .

-

..

Safety Assessment / Quality Assurance

An example of management- response to a safety significant issue involved the detection of several problems with refurbishment of the reactor trip breakers during receipt inspection. This action prevented installation of substandard breakers relied upon for a safet/ function in the reactor protection system. _In addition to detecting the faults, the licensee visited the vendor site to discuss the event and identify corrective actions. Additionally, the licensee documented ;he event in a letter to

-

the NRC vendor inspection branc Another example of responsiveness to a problem caused by a vendor was theE licensee actions in response to bottled hydrogen that~was contaminated with argon. The licensee visited the vendor, discussed the;-event, an identified effective corrective actions.- In addition to the-visit,.the~

plant manager discussed.the event and correction action with.the vendor.

l l-I l

l

-!

3'

..

,

e e

.

. ,

DETAILS I Persons Contacted i fE. Watzl, Plant Manager - 5

1. D. Hendele, General Superintendent, Engineering and Radiation Protection G. Lenertz, General Superintendent,liaintenance

1. A. Smith, General Superintendent, Planning and Services

1. il. Wadley, General Superintendent, Operations [

-

R. Lindsey, Assistant to the Plant Manager D. Schuelke, Superintendent Radiation Protection i

1. G. Hiller, Superintendent, Operations Engineering K. Beadell, Superintendent, Technical Engineering- i T. Breene, Superintendent, Technical Engineering-M. Klee, Superintendent, Quality Engineering ,

R. Conklin, Supervisor, Security and Services .:

G. Eckholt, Nuclear Support Services >

1. J. Leveille, Nuclear Support Services '

1. A. Hunstad, Staff Engineer ,

1. L. Anderson, Shif t Manager

1. P. Valtakis,-Shift Manager ,

1. Denotes those present at the exit interview of August 17, 1990, t Licensee Action on Previous Inspection Findings (92701) (Closed) Unresolved-Item 282/90006-01(DRP): Engineering Safeguards !

Actuation During Surveillance On May 18, 1990, while performing surveillance testing of the undervoltage detection circuit for the:No.15 safeguards bus, a t blown fuse caused the undervoltage detection logic to sense a falso undervoltage condition. The voltage restoration system stripped the No.15 safeguards bus and re-powered the bus via- the D-1 Emergency ;

Diesel Generator. The No. 12 Com)onent Cooling (CC) pump started on low pressure, shortly following t1e loss of power to the -operating No. 11 CC purp. The Nos. 11 and 13 Containment Fan Coil units; the 121 control room chiller and the 121 air compressor lost' power and were restarted as required, following bus restoratio The cause of the blown fuse was grounding the "C" phase voltage

-

detection relays across its protective fusing. This grounding occurred when a test lead attached to terminal wiring for the surveillance rotated from gravity, and came into contact with the adjacent wirin The inspector reviewed ~a past similar occurrence which was reported !

to'the NRC as LER 282/81-2 The December- 10, 1981, event was- a

'

similar in that the voltage restoration logic was also-unnecessarily-

! activated for a safeguards bus. However, the cause wasnot similar since the undervoltage signal.was derived from a test sequence error t

i

. .

.

.

performed by technicians. The 1981 event required procedure change:

to prevent recurrence which appear to have been effectiv The licensee generated a modification o Itarch 31, 1983, to install test point jacks enhancing the aerformance of safeguard bus logic testing. This modification was cancelled on October 26, 1986, and reinitiated by modification 86L942 which was later cancelled and reinitiated by liodification 89LO81. The licensee stated in LER 282/90007-LL that this %dification's priority has been elevated and will be performed during the next refueling outage for each unit (reference paragraph 6a). This matter is closed, (Closed)UnresolvedItemP82/90011-01: . Shield Building Ventilation System Inoperability This matter has-been reviewad, elevated to a violation, and is discussed in paragraph 8.a. The unresolved item is close (Closed) Unresolved item 282/90011-02: llissed Surveillances and the Surveillance Program This matter has been reviewed, elevated to a violation, and is discussed in paragraph 8.b. The unresolved item is close . Operational Safety Verification (71707, 93702) Routine Inspection

~

The inspector observed control room operations, reviewed applicable logs, conducted discussions with control room operators and observed shift turnovers. The inspector verified operability of. selected emergency systems, reviewed equipment control records, and verified the proper return to service of affected components; and conducted tours of-the auxiliary building. turbine building and external areas of the plant to observe plant equipment conditions including potential fira hazards. The in spector also verified that ,

maintenance work requests had been initiated for the equipment in need of maintenance, Control Room Activities '

On July. 3,1990,- the hydrogen supply was changed out for volume control tank (VCT) cover gas. On July 7, 1990, due to escalating radioactive gas level readings for Argon 41, an investigation was initiated. The hydrogen su contaminated with Argon (A)pplier to about determined the licensee 2 percent. .Tne, hydrogen supply was changed out the hydrogen supply again on July 10, 1990, with a ne !

hydrogen supply from the supplie '

While the contaminated hydrogen was in use, the.YCT dose field changed from about 100 mr/hr (contact) on the top of the VCT to a maximum of approximately 10 R/Hr (contact) at the same area. The

. .

-

.

.

RCS radioactive A-41 level changed from approximately 3.3 E-3 to a maximum of 3.1 E-1 microcuries/cc. Total radioactive gas concentration changed from approximately 5.0 E-2 microcuries/cc to a maximum of 3.4 E-1 microcuries/c A sysa engineer visited the hydrogen supplier to investigate the root cause prevent of the contamination and to work on corrective action to recurrenc This includes some piping changes for the large

,

hydrogen source to storage bottles to prevent unintentional mixing of other gas supplies. In addition to the visit, the Plant Manager discussed the event and corrective actions with-the hydrogen supplie The licensee issued an operations note on July 31, 1990,:regarding-the need to change the Unit 2 auxiliary building radiation wonitors (2R-30 and 2R-37) setpoints. These radiation monitor setpoints are determined on a monthly basis. The recent problems with Argon gas contamination during July resulted it: the Unit 2 auxiliary building radiation monitor setpoint changes. Because of the differences in sensitivity of the two monitors, the 2R-37 setpoint was placed considerably closer to background level than 2R-30. The licensee decided to place 2R-37 in the reset mode of operation since this monitor has traditionally experienced spiking and subsequent auto-actuations of the auxiliary building special ventilation syste The licensee later decided to return the 2R-37 setpoint to the previously higher value, place the monitor in the operational mode and declare the monitor out of service. This action resulted in the 2R-37 monitor providing the capability to give an alarm and autostart function, although at a higher than calculated setpoint, thus it provides a backup to 2R-30. Technical S the radiation monitors to be in service.pecifications required one of On July 27, 1990, during review of Unit 1 Reactor Log, the licensee discovered while SP-1172 radiation monitor IR-22 had been taken out of service was in progres This resulttd in a period of approximately three hours with Ventilation Systems discharging out Unit 1 Shield Building Stack and IR-22.(radiation monitor revuired by T. S.) being out of service. This matter-is unresolved ptnding inspector review (Unresolved 282 0012-01).

On August 11, 1990, the licensee reported to the NRC duty officer that an auto start of the #12 component cooling (CC) pump occurre The start occurred during a Residual Heat Removal surveillance which ;

required running an additional component cooling pump. The autostart occurred when the additional CC pump was stopped. Th operator did not hold the control switch'in the off position long enough to compensate for pressure' oscillations. The pump started on 3 a low pressure autostart signal. This event will be tracked by the LER(282/90011-LL).

c. Operational Concerns /Part 21 Notification -

On July 12, 1990, Westinghouse notified NRR that'it had found an ..

error in its LOCA analysis. The erroneous analysis had been used to

j

,

.

..

establish the upper limit of 2.5 for the heat flux hot channel factor, FQ. Westinghouse stated that the actual limit for FQ, accounting for the error, would be less than 2.5. The measured FQ for Unit I was 1.94 on July 13, 1990. Standard correcticns for

-

manufacturing tolerances, measuring uncertainty, and operational transient? resulted in an FQ of approximately 2.33. On July 14 Westinghoase notified the licensee that current analytical results with an FQ of 2.32 were not successful in meeting the 10 CFR 50, Appendix K LOCA analysis requirements of less than 2200 degrees F. peak clad temperature. Westinghouse expected that continuing analysis would indicate that peak clad temperature would be acceptable with an FQ of 2.32. At this point the licensee decided to derate Unit 1 by 3 percent reactor powe On July 14, 1990, the licensee notified the'NRC duty officer that Unit I was being derated 3 percent to an operational limit of 97 percent to compensate for operating limit concerns. The Unit 1 power reduction to 97 percent was complete at 1845. The power range reactor trip setpoints were reduced by 3 percent to 105 percen This action was complete at 210 Since the FQ limit is inversely proportional to power, by operating at 97 percent, the FQ limit of 2.32 was raised to approximately 2.3 Because the corrected FQ for Unit 2 was 2.07 at~ full power the licensee considered Unit 2 to have adequate margin from the 2.32 FQ limit.

'

On July 23, 1990, Westinghouse notified Prairie Island that the LOCA reanalysis with an FQ of 2.32 was successful in obtaining a peak clad temperature of less than 2200 degrees F. BascJ on this information and newly calculated operational transient correction factor curves for the current fuel load, a corrected FQ of 2.25 was measured which allowed Unit I to return to 10J percent power on July 27. The reactor trip setpoint for Power Range Nuclear Instruments was left at 105- percent, in anticipation of a future derate for F delta h concern On July 16,-1990, Westinghouse Electric Corporatiori provided a 10 CFR Part 21 rmtification of a design error involving the decay heat model of W LOBRA/ TRAC computer code used in the LOCA analysi This concern aiid licensee actions will be tracked by the Part 21'

,

notification (HS-NRC 90-3528).

4. Maintenance Observation '71707. 37/00. 62703)

Routine, preventive, and corrective maintenance activities were observed to ascertain that they were conducted in accordance with. approved procedures, regulatory guides, industry codes or standards, and in conformance with Technical Specifications. The following items were considered during this review: adherence to limiting conditions for-operation while components or systems.were. removed from service, approvals obtained prior to initiating the' work, activities accomplished'

using approved procedures and inspected as applicable, functional testing

. ..

'

,

,

. .

!

nd/or calibrations performed prior to returning components or systems to servite, quality control records maintained, activities accomplished by '

qualified personnel, radiological controls implemented, and fire prever tion controls implemente ;

Portions of the following maintenance activities were observed during the inspection period: i t

- Overpower Delta Temperature Channel Distable Repair .

- Cleaning of Emergency Diesel Generator (EDG) D2 Lube Oil Cooler !

Water Sides  ;

- Replacement of Copper Gaskets for Fuel Line to Cylinder Jacket ;

Adapters i

- Replacement of EDG D2 Timing Relays .

- Calibration of EDG D2 Local Panel Meters No violations or deviations were identifie . Surveillance (61726,71707)

The inspector witnessed portions of surveillance testing of safety-related systems and components. The ins section included verifying that the tests were scheduled and performed wit 11n Technical -

Specification requirements by observing that procedures were being followed by qualified operators, that Limiting Conditions for Operation (LCOs) were not violated, that system and equipment restoration was completed, and that test re:;ults were acceptable to test and Technical Specification requirement SP 1035 Reactor Protection Logic Test

-

SP 1090 Containment Spray Pump No violations or d'eviations were identifie . Regional Initiatives (Closed) Information Notice No. 89 79: Degraded Coatings and Corrosion of Steel Containment VerJe'Is The licensee performed an assessment of the information notice and'

concluded that present surveillance procedures in place were sufficient to address the concerns identified. Specifically, the information notice contained examples of corrosion in the annular-space between the steel containment shell and the concrete shield building. The examples provided all involved the steel'shell area near the annulus concrete floor or below. The corrosion was attributed to the lack of sealant at the interface between the shell and the annulus floor, which allowed accumulated water to flow onto the steel shel The licensee reviewed two existing surveillance procedures which-addressed the concerns identified. SP1071-(2071), Integrated Leak; Test Procedure, Section 6.0, contains a step to visually inspect the steel shell for structural deformation and includes the concrete

-

.

steel interface region. Additionally, SP 1123(2123), Inspection of Concrete - Steel Interface Adjacent to the Containment, was '

developed in 1983 to inspect this particular area of concern. The

. surveillance is performed at a minimum of every refueling outage by a maintenance supervisor. The visual inspection includes both sides ,

of the containment shell at the steel concrete interface and ;

requires observation for corrosion and any degradation of the sealant ,

between the tw9 materials. Any discrepancy requires issuance o work request to remedy the condition. Guidance in the surveillance *

procedure provides specific instructions for remedying of any defects identifie ,

The licensee has had procedures in place which appear to adequately address the issues identified in the information notice. The ,

inspector also verified that supplement I to this information notice r dated June 29, 1990, was received by'the licensee and assigned for !

~

revie _ Reactor Trips Breaker (08-50) Problems Background  ;

On July 19, 1990, the licensee met with the inspector to discuss !

recent problems with spare reactor trip breaker refurbishmen '

'

Discrepancies were identified during a receipt inspection performed on site by the licensee. These spare breakers were not installed

,

into servic The licensee sends DB-50 breakers to the vendor (Westinghouse) for !

refurbishment. This activity includes teardown and reassembly. Of 3 critical importance is inspection and restoration of the '

undervoltage trip mechanis The licensee has sent six of ten DB-50-breakers used in rod control I (eight installed, two spares) to Westinghouse for refurbishmen <

This activity is conducted in accordance with a controlled i Westinghouse procedure, i Detailed Discussion During a receipt inspection on February 16, 1990, the licensee '

discovered that bolts securing the breaker sole unit to its frame were loose on one of the breakers. 'The tecinical engineering group determined that this condition has the potential to slow the breaker e opening function. The safety significance'of the as-found condition was minimized by the system design of two reactor trip breakers in -1 series, which allows either breaker opening to provide the safety-function of. interrupting power to.the control rod drive mechanisms, allowing the control rods to drop into the core, q

A second problem was observed on the same reactor trip breaker during the receipt inspection. The #21 secondary contact was observed to be'

bent. The licensee did not attempt to determine whether the contact was operational.:but instead ordered the contact replaced. The

L

. .

.

.

.

effect of the contact being inoperable would be loss of one input to i the feedwater isolation logic, which senses a reactor trip by either reactor trip breaker being open. Since only one of the two series ;

installed breakers would have been affected, the safety significance of this loss of input was minimal. The feedwater isolation logic -

only requires one input to perform its functio Theabovetwodeficienciesinvolvedonebreaker(#3-24Y7278). The other breaker receipt inspected (d224Y72738) disclosed a wiring error. The error consisted of the lead for the blowout coil and the v X contact in the closing coil being interchanged. The effect of the error is the breaker would not have closed. With the system design of breakers in series, the rod control mechanisms could not be ,

energized and subsequently withdrawn. Thus, this-conditien involved ,

minimal safety significanc The licensee has sent four breakers'to the vendor previously without ;

performance concerns identified. In response to the deficiencies discussed above, the licensee sent representatives to the ,

refurbishment facilities to review procedural controls and discuss '

the problems encountered. The licensee has discussed several corrective actions with the vendor which include addition of bolt torquing values and verification steps to the refurbishment

'

procedur The licensee has reviewed the deficiencies for Part 21 reportability and concluded that the onsite event is isolated and thus not reportable. The licensee communicated this event to the NRC in a i letter. dated August 2,1990, to the Vendor Inspection Branc , Licensee Event Reports (Closed)LER 282/90007-LL: Autostart of D1 Emergency Diesel Generator Due to Short circuit Caused By Test Leads During Surveillance Test.

l I

The inspector reviewed this event, and one past similar event and .

the corrective actions to prevent recurrence. (ReferenceParagraph 2a.) The inspector observed portions of the test following_the event-and concluded the personnel involved were experienced and conscientious in their actions. The placement ~and position requirements for test leads in this particular test are perilous i and the likelihood for generation of an undesired undervoltage signal '

due to shorting terminal contacts during testing is high. The ;

licensee has placed a priority on completion of a modification to install test point jacks which would eliminate the shorting of-l terminal wiring for this surveillance. The licensee had previous l modifications to accomplish this improvement. The licensee states in l the LER that the applicabTe modification will be completed during the l next refueling outage for each unit.

!-

'

l l

i

-

, .,

-

.

<

.

8. Followup on Previous Inspection Findings Both Trains of Shield Building Ventilation Inoperable Background The inspector completed an investigation of the July 27, 1990, event involving both trains of the Shield Building Ventilation System (SBVS)beinginoperable(ReferenceInspectionReport 282/90011). The inspection findings are discussed belo Event Discussion On June 27, 1990, while Unit I was operating at 100 percent power, both trains of the Shield Building Ventilation System were made inoperable. The No.12 Shield Building Ventilation System was removed from service for electrical preventive maintenance (PM).

During the No.12 SBVS removal from service, the No.11 SBVS exhaust fan electrical breaker was opened instead of the No.12 exhaust fan breaker._ A chronology is provided belo :30 Preventative Maintenance packages initiated on "B" train oc Unit 1 Shield Building Ventilation System motor control center starter This included the starters for:

-

1. 12 Shield Building Exhaust Fan

-

1. 12 Shield Building Recirculating Fan-

-

1. 12 Shield Buildin? DAC Filter Heater

-

About 8:20 a.m. work begsi, opening the breakers for the above electrical loads to allow m, ,< ring of the circuit breakers and ,

motors. This was one of the first steps of the preventive i maintenance procedur :05 The next step in the PM procedure was- to remove the circuit l breaker / starter assembly and perform maintenance on them. At this point an electrician determined-that the incorrect Exhaust Fan breaker was opene The circuit breaker for #11 Exhaust l Fan had been opened'instead of #12. This was reported to the L

control room. The initial evaluation was that both trains of'

Shield Building Ventilation were inoperabl :10 .

-

The circuit breaker for #11 Shield-Building Exhaust Fan was -

closed. An _ operability test' for #11 train of Shield Building Exhaust was initiate ~10:40 The operability test was ' completed and the #11 train of Shield '

Building Exhaust was declared operabl . .

.

,

b

- 11:40 ;

The licensee reported the above event to the NRC operations duty officer via the ENS lin The licensee utilized new electrical preventative maintenance procedures for the first time for the #12 SBVS electrical '

supply breakers. These breakers are located on two 480 VAC Hotor Control Centers (NCC) in the immediate area of the SBVS. The ,

effect on the !11 train of SBVS without the exhaust-fan is of minimal -

significance due to its relatively small capacity of 200 CFM. The -

recircul.ition fan capacity is 5000 CFM, thus the loss of the #11 exhaust fan represents a 4 percent total system flow loss. Without *

the 9.;ust fan the SBV system flow is hydraulically split between 1 ecirculation and exhaust flow out the exhaust stack. On ane 28, 1990, the licensee performed a surveillance on the #12 SBVS '

wlth the recirculation fan only to duplicate conditions that existed on June 27. Test results indicated that the #12 SBVS would perform l as required to meet the surveillance performance requirement contained within Technical Specification 4.4. t Root Cause Analysis  ;

The reason that the #11 SBVS Exhaust Fan was made inoperable instead .

of #12 was primarily due to a typographical error. The Motor ?

Control Center (NCC) number for #11 exhaust fan is 1H1-Bl. The MCC number for #12 exhaust fan is IH2-Bl. The PM procedure for the #12

exhaust fan breaker indicated #1M1-B1 as the cell identifier. This-nomenclature indicated #11'instead of #12 exhaust fan, which the -

electrician utilized, and resulted in selecting the wrong SBV train exhaust fa .

A secondary cause was personnel error. The wrong breaker was selected despite two other pieces of information that indicated the i proper breaker identification. Each MCC cell-(i.e. breaker location) is identified by three unique identifiers: -

' The MCC and cell number: example #1M1-B . The motor number: example #126-3 . The description: example #12 Shield Building Exhaust Fan brea ke .

!

All three identifiers were referenced in the procedure. The-MCC/ cell nunber listed on the PM procedure did not agree with the

! motor number or the description, although the cell nunber did. Each l identifier should be ccrrect in the PM procedures. In' this ) resent case the electrician utilized only the cell identifier, whic1 ,

indicated the wrong train SBVS exhaust fa Enforcement

'

Technical Specification 3.6.H, containment, Shield Building >

Ventilation System allows only one train to be inoperable with reactor coolant system average temperature above 200' With both 4 trains inoperable, Technical Specification 3.0.C applies which 12 .

-

.

.

-

.

requires when any Limiting Condition for Operation , and is not met hour initiate the action necessary na toone place the a condition in which the equipment is not required to be OPERABLE .

Contrary to the above, on June 27, 1990, from approximately 8:20 a.m. to 10:10 a.mwith Unit I about 200* F ,

Shield Building Ventilation Systems were r., both the fiumber 11 and 12 improper opening of the ilumber 11 exhaust fan breakerendered inoperab

.

Action was which the Shield Buf1 ding Ventilation System w be operabl requirements (282/90012-02(DRP)).This is a violetion of Technical Spe Review of Surveillance Program LER Review On 11ay 24,1990, regarding the failure the tolicensee submitted an LER (282/90004)

aerform a technical specification required surveillance witlin a requir~' time frame Surveillance Test SP 1042 Resistance Temperature Detecto (RTD) Bypass Flovmieter Functional 11onthly Test performed on April 16, 199 , was due to be allow this test to be performed as late as 1990 AprilThe 25 percent grace This surveillance was not completed until23, , 1990. 24 April .

The licensee surveillanc discovered the error and promptly e e perform d th recent past at Additional scheduling errors have occurret Prairie Islan in the the eventreport inspection and perio the surveillance program during ext the nThe inspector dec the licensee submitted LER During the current inspection period 282/90-10 regarding a miss d e surveillance due to the rescheduling of another .

surveillance The licensee submitted LER 282/90-10 on July 30, 1990, which discussed the surveillance SP 1029. Radiationm Test, Syste which On percen was not performed within a 30 day period, plus 25 pointed out March 15, 1990, that for a few surveillance procedo es, athe. plant Quali discrepancy,exhted schedu lt .

Between March 15, and March between master the due dates 21, 1990 the Radiation conferred to resolve the discrepancie nator Protection Sup master were schedule change and the Radiation As a result Protectionboth theGroup's,schedul April 25, 1990. SP1028 was rescheduled from April 4 to e need for an additional test, since then new due date ha advanced three week Protection Supervisor and his supervisor resulted in thLater mistaken was belief not performe that the additional test was e

, and not required

-

L

' t

. .

..

.

A discussion with the licensee Regional Management and the inspectorwasheldtoaddressInterpretationoffixed -

surveillance schedules, and Technical Specification '

requirements. Technical Specification Section 4.0 states that,

" Specific time intervals between tests may be adjusted plus or i minus 25 percent. . . ." This means that a monthly test may be !

-performed 7 days on either side of its due date. However, when the fixed schedule is. changed or deviated from, the NRC will i enforce the surveillance frequency plus 25 percent from the date the last surveillance was performed rather than schedule SP3028 was last performed on March 12, 1990. The fixed date was changed and the surveillance was delayed until !

April 20, 1990. This period from the last performance day exceeds 30 days plus 25 percen . Surveillance program l The inspector received Operations Manual Section G1 Rev 7.-

i Surveillance, This procedure controls the surveillance program t at Prairie Island, f The program requires a quarterly Master Surveillance Schedule e be developed for all surveillances which appear on the surveillance test index. Each surveillance has a group

,

'

responsible for performing the surveillance designate ;

Individual Group schedules are also developed and contain the' :

surveillances designated for the group, and the performance due date. The group supervisor has the responsibility to ensure- -

surveillances are completed within the 25 percent grace period, i Review of the completed surveillances to ensure compliance with the schedule occurs during the.next quarter. This is done in an activity called "end of quarter reconciliation." This activity requires the surveillance. coordinator to account for- ;

all surveillances due during the quarter. At Prairie. Island the surveillance coordinator is an ' 'ividual who has the '

collateral duty of being a system en veneer. Currently the surveillance coordinator also is the system engineer for.the Unit I containment ventilatic.a systems, and fire protectio _ An ongoing or " front end" review of timely surveillance '

performance is limited to a document contro1~ activity where completed surveillance dates are entered into the Sperry -

computer cystem for date comparison with the scheduled surveillance date for the current quarter. Any anomalies are ,

printed out. The anomalies are reviewed by the surveillance . '

coordinator. This process typically'does not . detect.a missed surveillance due date within a time frame where the -

surveillance cwid be performed on time (i.e. within the--due date).

!

- .

, *

.

!

?

The Operations Committee (00) is required by Section 4.10 of l the procedure to review the adequacy of Surveillance Schedule ;

process on a periodic basis. With the above two reportable !

events, the OC has begun considering changes to the Surveillance program, however, no specific changes have been :

identified or implemented as of the end of the report perio . Enforcement [

Technical Specification 4.1 specifies minimum frequency and l types of surveillance to be applied to plant equipment and l conditions. Technical S)ecification 4.0 states t1at the ,

'

specific time intervals aetween tests may be adjusted plus or minus 25 percent to accommodate normal test schedules with the ;

exception that, the intervals between tests scheduled for

'

refueling shutdowns shall not cxceed two years. Technical Specification 4.1. A requires calibration, testing and checking' ;

)

of instrument 4.1- channels This table be the requires performed as specified instrument channel by(Table item 32) T.S. -

for RTD (reactor coolant) Bypass Flowmeter to be functionally-tested monthl ,

Surveillance Procedure SP 1042, Resistance Temperature Detector (RTD) Bypass Flowmeter Functional Monthly Test, meets this *

requirement and was due to be performed on April 16, 1990. The '

25 percent grace period would have allowed this' test to have <

been performed as late as April 23, 1990. Due to a scheduling error, this surveillance was not completed until .

April 24, 1990. This is one example of a violation of Technical Specification 4.1. Technical Specification Table T.S. 4.1-1 also requires the ,

instrument channel (item 35b.) for radiation monitors (listed

'

in Table T.S. 3.15-2) to be functionally tested. Surveillance :

Procedure SP 1028, Radiation System Test, meets this requirement and was due to be Jerformed on April 4,199 The 25 percent grace period would iave allowed this test to be ;

performed as late as April-11, 1990. Duc to a personnel error, the test was not performed until April 20, 1990. The two above examples violate Technical Specification Surveillance !

requirements (Violation 282/90012-02;306/90012-02(DRP)). j

' Exit (30703)

The inspector met with the licensee representatives denoted in aaragraph

'

1 at the conclusion of the report period on August 17, 1990. T 1e inspectors discussed the purpose and scope of-the inspection and the findings. The inspectors also ' discussed the likely information content ,

of the inspection report with regard to documents or processes reviewed'

by the inspector during the inspection. The licensee did not identify any documents or processes as proprietar !

15