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Insp Rept 50-271/89-02 on 890214-0417.No Violations Noted. Major Areas Inspected:Actions on Previous Insp Findings, Operational Safety,Security,Plant Operations,Maint, Surveillance & Engineering Support
	ML20246L926
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	05/04/1989
From:	Haverkamp D; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20246L923	List: IR 05000271/1989002; ML20246L919;
References
	50-271-89-02, 50-271-89-2, NUDOCS 8905180429
	Download: ML20246L926 (66)
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U.S. NUCLEAR REGULATORY COMMISSION

! REGION I l

l- Report N /89-02

. Docket N License No.'DPR-28 Licensee: Vermont Yankee Nuclear Power Corporation RD 5, Box 169 Brattleboro, Vermont 05301 Facility: Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont Inspection Conducted: February 14 - April 17, 1989 Inspectors: Geoffrey E. Grant, Senior Resident Inspector Douglas A. Dempsey, Reactor Engineer Lawrence T. Doerflein, Project Engineer Approved by: kb/ -

d f/4//59 DonaldR.Haverkamp,Chieff Date Reactor Projects Section No. 3C Inspection Summary: Inspection on February 14 - April 17,1989 (Report No. 50-271/89-02)

Areas Inspected: Routine inspection on daytime and backshifts by a resident inspector of: actions on previous inspection findings; operational safety; security;' plant operations; maintenance and surveillance; engineering support; licensee event reports; licensee response to NRC initiatives; and, periodic report Inspections included 261 hours0.00302 days 0.0725 hours 4.315476e-4 weeks 9.93105e-5 months during normal working hours, 67 hours7.75463e-4 days 0.0186 hours 1.107804e-4 weeks 2.54935e-5 months of backshift coverage, and 70 hours8.101852e-4 days 0.0194 hours 1.157407e-4 weeks 2.6635e-5 months of deep backshift coverag Results: General Conclusions on Adequacy, Strength or Weakness in Licensee Program The licensee failure to perform a required monthly analysis of the diesel fuel oil storage tank contents represents a breakdown in the effectiveness of the licensee corrective action program (see Section 6.2 for details).

Implementation of the monthly analysis was in response to an NRC unresolved issue pertaining to Technical specification 4.10.C.2 requirements. Admini-strative control of interim corrective measures failed during the six-month period the licensee took to develop the permanent corrective actio Interim controls were informal and implementation of permanent corrective actions was not expeditious. Two other examples of ineffective corrective h

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C Inspection Summary (Continued)

actions have occurred in the past several months: service water effluent

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. radiation monitoring system sampling (IR 88-14), and radiological control area posting (IR 88-19). Licensee commitments for an improved corrective action program resulted from these occurrences and was implemented in early December.1988. Additional problems with corrective action effec-tiveness are discussed in Sections 6.6 and 6.11. These issues relate to NRC-identified long-standing deficiencies. Although the licensee has implemented measures to address these items, correction has been less than fully effectiv Long term effectiveness of the licensee improved corrective action program will continue to be assesse Overall coordination and control of outage activities were excellent. The licensee demonstrated effective communications and teamwork when resolving emergent work issues during the outage. Inspection of 4KV buswork, repair of RHR heat exchangers, repair of RHRSW check valves, and expanded inspec-tions of feedwater check valves were examples of significant unplanned maintenance activities that tested the licensee's ability to effectively respond to challenges. Numerous complicated special tests and surveill-ances were anticipated, well prepared, and successfully executed. However, performance during a number of more routine activities indicated occa-sional diminished control. Two Unusual Events and several engineered safety feature (ESF) actuations were either due to or displayed ineffec-tive communications or a lack of attention to detai It appears that unusual or infrequent operations, as noted above, receive excellent licen-see attention and execution, while a less questioning approach is exhib-ited during routine or " minor" activitie Instances of lapses in effec-tive control have been discussed with licensee management. Although corr-ective actions for individual problems appear to be adequate to prevent recurrence, a more global and probing licensee examination of potential underlying common causes is neede . Unresolved Items An unresolved item was identified during this inspection period concerning acceptance and impact of battery cell temperature differentials greater than 5 degrees F (Section 10).

An unresolved item was identified during this inspection period concerning the containment integrated leak rate test (CILRT) test methodology and is pending NRC review of the final CILRT test report (Section 7).

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TABLE OF CONTENTS j l

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Page Persons Contacted. . . . . . . . . . . . . . . . . . . I Summary of Facility Activities . . . . . . . . . . . . 1 Status of Previous Inspection Findings (IP 71707, 92702, 92701). . . . . . . . . . . , . . . . . . . . . 1 3.1. (Closed) Unresolved Item 87-09-05:

PAR Rack Criticality Analyses . . . . . . . . . . 1 3.2 (Closed) Unresolved Item 87-02-04:

Battery Temperature Limits. . . . . . . . . . . . 2 Operational Safety (IP 71707, 71710) . . . . . . . . . 2 4.1 Plant Operations Review . . . .. ....... 2 4.2 Safety System Review. . . ............ 3 4.3 Inoperable Equipment. .............. 3 4.4 Review of Lifted Leads, Jumpers and Mechanical Bypasses. . . . . . . . . . . . . . . . . . . . 3 4.5 Review of Switching and Tagging Operations. . .. 4 4.6 Operational Safety Findings . . . . . ...... 4 Security (IP 71707). . . . . . . . . . . . . . . . . . 4 5.1 Observations of Physical Security . ....... 4 Plant Operations (IP 71707, 93702, 40500). . . . . . . 5 6.1 Outage Organization . . . . . . . . . ...... 5 6.2 Outage Activities . . . . . . . . . . . . . . . . 5 6.3 Plant Startup Preparations and Activities .. 7 6.4 Primary Containment Isolation System (PCIS)

Actuations - Group.III. . . . . . . . . . . . . . 10 6.5 Diesel Fuel Oil Analysis. . . . . . . . . . . . . 13 6.6 Switchgear Room Fire Suppression System Actuation . ................... 14 6.7 Unusual Event - Reactor Water Level Decrease. . . 17 6.8 Partial ECCS Actuation. . ............ 19 6.9 Leaking Fuel. .. . . . . . . . . . . . . . . . . . 20 6.10 Unusual Event - Torus Water Level Increase. . . . 21 6.11 Event Notifications . . . . . . . . . . . . . . . 22 i

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Table of Contents (Continued) Page Maintenance / Surveillance (IP 71707, 61726, 62703, 70313). . . . . . . . . . . 22 7.1 Snubber Failure . . . . . . . . . . . . . . . . . 22 7.2 Local Leak Rate Testing . . . . . ........ 23 7.3 Containment Integrated Leak Rate Test (CILRT) . . 25 7.4 Electrical Buswork Insulation Degradation . . . . 29 7.5 Feedwater Check Valve Flaw. . . . . . . . . . . . 30 Engineering Support (71707, 37828) . . . . . . . . . . 32 8.1 Outage Modifications. . ......... ... 32 Licensee Event Reporting (LER) (IP 93702, 90712) . . . 36 9.1 LER 89-03 . . . . . . . . . . . . . . . . . . . . 37 9.2 LER 89-04 . . . . . . . . . . . . . . . . . . . . 37 9.3 LER 89-05 . . . . . . . . . . . ........ 37 9.4 LER 89-07 . . . . . . . . . . . . . . . . . . . . 37 9.5 LER 89-08 . . . . . . . . . . . . . . . . . . . . 37 9.6 LER 89-10 . . . . . . . . . . . . . . . . . . . . 38 9.7 LER 89-11 . . . . . . . . . . . . . . . . . . . . 38 9.8 LER 89-12 . . . . . . . . . . . . . . . . . . . . 38 9.9 LER 89-13 . . . . . . . . . . . . . . . . . . . . 38 9 10 LER 89-15 . . . . . . . . . . . . . . . . . . . . 39 1 Review of Licensee Response to NRC Initiatives:

(IP 71707, RTI 87-07). . . . . . . . . . . . . . . . . 39 10.1 Region I TI 87-07: Storage Battery Audit . ... 39 1 Review of P.. .adic and Special Reports (IP 71707). . . 44 12. Management Meetings (IP 30703) . . . . . . . . . . . . 45 Attachment A: Table - Key Operational Activities Attachment B: Figure 1 - Residual Heat Removal System "A" Loop

The NRC Inspection Manual inspection procedure (IP) or the Region I temporary instruction (RTI) that was used as inspection guidance is listed fnr each applicable report sectio T-2 I

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DETAILS 1 Persons Contacted J l

Interviews and discussions were conducted with members of the licensee staff and management during the report period to obtain information pertinent to the areas inspected. Inspection findings were discussed periodically with the management and supervisory personnel listed belo Mr. P. Donnelly, Maintenance Superintendent 1

Mr. R. Grippardi, Quality Assurance Supervisor Mr. S. Jefferson, Assistant to Plant Superintendent Mr. J. Herron, Operations Supervisor Mr. R.'Lopriore, Maintenance Supervisor Mr. M. Metell, Engineering Support Supervisor Mr. R. Pagodin, Technical Services Superintendent Mr. J. Pelletier, Plant Manager

Mr. R. Wanczyk, Operations Superintendent Mr. T. Watson, I & C Supervisor Mr. W. Wittmer, Construction Superintendent

Attendee at post-inspection exit meeting conducted on May 4, 198 . Summary of Facility Activities The plant entered a planned refueling and maintenance outage on February 11, 1989. The outage was completed essentially on schedule with plant startup on April 7 and the generator phased to the grid on i April 10, 1989. A summary of key operational activities during the outage !

appears in Attachment A to this report. Additionally, two Unusual Events (UE) were declared during the outage. On March 9 an UE was declared due to an unanticipated decrease in reactor water level (Section 6). On April 9 an UE was declared due to a torus water level increase (Section 6). Status of Previous Inspection Findings 3.1 (Closed) Unresolved Item 87-09-05: Licensee to Address PAR Rack Criticality Analyses and Changes to License Limits for Fuel Bundle U-235 Loading Required as a Result of the High Energy Fuel Desig License Amendment No. 104, issued May 20, 1988, allowed the licensee to rerack the spent fuel storage pool. This reracking consisted of removing the existing Frogrammed & Remote, Inc. (PAR) racks and in-stalling ten new Nuclear Energy Services (NES) high density spent ;

fuel storage racks. To date, the licensee has removed all the PAR racks and installed seven of the ten NES racks. Based on discussions with licensee personnel, the inspector noted that this portion of the modification was completed prior to fuel handling for the 1989 refuel-ing outag This was the first refueling for which the licensee !

received and installed fuel bundles with an average enrichment of 3.25 weight percent (wt %) U-235. Therefore, additional criticality analysis for the PAR racks as a result of using high energy fuel bun-dies is not necessar _ _ _ - _ _ - - _ _ - _ __ _ __ _ ___ __ _ _ - ___

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Also, license Amendment No. 108, issued September 9, 1988, revised Technical Specification 5.5.E to limit the infinite lattice multi-plication factor of any segment of a fuel assembly stored in the spent fuel pool or the new storage facility to 1.31. This includes storage of high energy bundles. The inspector had no further ques-tions concerning this ite This item is close .2 (Closed) Unresolved Item 87-02-04: Battery Temperature Limit The issues raised by this unresolved item involved the effects of low battery temperatures on station battery capacity margins and licensee actions to assure that batteries remain within operability limit The licensee evaluated this issue irt Service Request 87-18, Battery Temperature Review, dated April 27, 1988 and concluded that no oper-ability problems existed as a result of low room temperature Revi-sion 1 to Vermont Yankee Calculation (VYC)-298, " Main Station Battery Sizing", derated the batteries to account for observed temperatures lower than that previously assumed in the Final Safety Analysis Report (FSAR). The licensee has initiated a program to monitor a selected cell in the battery of most concern (main station battery "B") on a daily basi Should this cell temperature fall below the minimum assumed in the new sizing calculation, the average temperature of the battery will be determined and re-evaluated to assure operabilit Based on inspector review of licensee calculations and proposed act-ion, this item is considered close . Operational Safety 4.1 Plant Operations Review The inspector observed plant operations during regular and backshift tours of the following areas:

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Reactor Building Fence Line (Protected Area)

Diesel Generator Rooms Intake Structure Vital Switchgear Room Turbine Building Control room instruments were observed for correlation between chann-els, proper functioning, and conformance with technical specifica-tions. Alarm conditions in effect and alarms received in the control room were reviewed and discussed with the operators. Operator aware-ness and response to these conditions were reviewed. Operators were found cognizant of board and plant conditions. Control room and shift manning were compared with technical specification requirement Posting and control of radiation, contaminated and high radiation areas were inspected. Use of and compliance with radiation work per-mits and use of required personnel monitoring devices were checke Plant housekeeping controls were observed including control of flamm-able and other hazardous materials. During plant tours, logs and rec-ords were reviewed to ensure compliance with station procedures, to

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determine if entries were correctly made, and to verify correct commu-nication of equipment status, These records included various opera-ting logs, turnover sheets, tagout and jumper logs, and potential reportable occurence reports. Resident backshift inspections of plant activities were performed on February 14-17, 22, 23, 27, 28; March 1-3, 6, 9, 10, 13, 14, 23, 28, 31 and April 7 and 13. Deep backshift inspections were conducted as follows:

Date Time March 2-3 6:00 p.m. - 4:00 March 4 7:00 a.m. - 9:00 March 5 12:15 p.m. - 4:45 March 14 9:00 p.m. - midnight March 23 9:00 p.m. - midnight March 28 9.n0 p.m. - 11:45 April 7 : 10 p.m. - 1.1:45 April 13 9:00 p.m. - 11:30 April 16 10:00 a.m. - 7:45 Operators and shift supervisors were alert, attentive and responded appropriately to annunciators and plant condition .2 Safety System Review The emergency diesel generators, reactor core isolation cooling, core spray, residual heat removal, standby gas treatment, residual heat removal service water, and safety related electrical systems were reviewed to verify proper alignment and operational status in the standby mode. The review included verification that (1) accessible major flow path valves were correctly positioned: (ii) power supplies were energized, (iii) lubrication and component cooling was proper, and (iv) components were operable based on a visual inspection of equipment for leakage and general conditions. No violations or safety concerns were identifie .3 Inoperable Equipment Actions taken by plant personnel during periods when equipment was inoperable were reviewed to verify: technical specification limits l were met; alternate surveillance testing was completed satisfactory-ily; and, equipment return to service upon completion of repairs was proper. These reviews covered numerous occasions of equipment ren-dered inoperable for planned maintenance throughout the outag Licensee control of the process was consistently good with a few exceptions discussed in Section .4 Review of Lifted Leads, Jumpers and Mechanical Bypasses Lifted lead and jumper (LL/J) requests and mechanical bypasses (MB)

were reviewed to verify that controls established by AP 0020 were met, no conflicts with the technical specifications were created, the l

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requests were properly. approved prior to installation, and a. safety evaluation in accordance with 10 CFR 50.59 was prepared if require l

. Implementation of the requests was reviewed on a sampling basi ,

? The LL/J and MB process and administration was monitored throughout' i

.the outage. Additionally, the entire LL/J and MB outstanding items list was reviewed as part of a comprehensive pre-startup systems l verification. process. The LL/J and MB controls required'for mainte-nance activities during the outage were. appropriately cleared prior to plant startu Remaining bypasses were verified as correct, necessary' and appropriately documented. Licensee control of this :

process was good with the exception noted in Section .5. Review of Switchirig and Tagging Operations 'j

The switching and tagging log was reviewed and tagging activities H were inspected to verify plant equipment was controlled in accordance l with the requirements of AP 0140, Vermont Local Control Switching -!

Rules. Switching and tagging orders were reviewed for many of the i-equipment repairs noted in Section 4.3. Additionally, a thorough I review of switching and tagging activities was conducted as part of the pre-startup verification process. The volume of tagging resulting '

from outage-related activities required careful review to avoid over--

sights and system alignment problems. Licensee control of this pro-cess was goo :

4.6 Operational Safety Findings Licensee administrative control of off-normal system configurations by the use of LL/J, mechanical bypass, and switching and tagging pro-cedures, as reviewed in Sections 4.3, 4.4 and 4.5, was in compliance with procedural instructions and was consistent with plant safet Overall control of administrative processes for the coordination of plant activities was good. However, some lapses in attention to detail were noted and are further described in Section 6. Many com-plicated evolutions were well planned and executed. Plant operations were routinely conducted in a professional manner in an atmosphere of control and competence. Backshift inspections consistently found operators to.be alert and attentive. Throughout the outage the licen- j see took measures to control plant cleanliness and material condition ;

Successful implementation of these measures resulted in a relatively '

clean and uncluttered plant at startup. Although at the conclusion of this report period some isolated areas of the plant still required restoration, conditions did not adversely impact operation . Security 5.1 Observations of Physical Security Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that controls were in accor-dance with the security plan and approved procedures. This review

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1 included the following security measures: guard staffing; vital and protected area barrier integrity; maintenance of isolation zones; and,. Implementation of access controls, including authorization, badging, escorting, and searche No inadequacies were identifie ) Plant Operations ;

6.1 Outage Organization The outage organization was established essentially along the normal operational organization tree. An Outage Manager was designated by and reported to'the Plant Manager and was responsible for the conduct of the outage. Normally filled by the Operations Superintendent, this position was periodically rotated to other superinter. dents to maintain full-time coverage. The outage organization reported to the .;

Outage Manager on all matters pertaining to outage-related activi- ,

ties. Daily outage meetings were held.in the morning and chaired by the Outage Manager. These meetings were attended by all key outage supervisory personnel and served to monitor outage progress, provide j activity planning and coordination, identify and resolve schedule or work conflicts and discuss near-term activities. Changes resulting from these meetings were assimilated by the Outage Planner and used )

to develop and modify the outage plan and schedule. An oversight l group was estabished to aid in transition through the various outage phases. This group was tasked with verification of conditions and activities necessary to progress through the various outage milestone Culmination of this process was the determination that the. plant was i prepared to return to power operations. Critical item tracking, check-

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lists and other administrative controls were used to achieve a smooth '

progression through the outage milestone Overview and control of the outage culminated with preparations for reactor startup. A separate bar chart and schedule were developed for this phase of the outage. Preparations were controlled by

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checklists, administrative procedures and detailed overview by the Plant Operations Review Committee (PORC). The PORC involvement in this process was noteworthy, as PORC review of maintenance, surveil-lance, modifications, required retests, and operability determina- ,

tions was extensive. Also reviewed for acceptability were lifted '

leads, jumpers, mechanical bypasses, and station tagouts. These comprehensive reviews provided assurance that plant conditions could support a safe reactor startup and test program. This multi-day process demonstrated a commitment to safe operations and superior performanc .2 Outage Activities Outage XIV commenced on February 10, 198 This refueling outage was completed essentially on schedule after eight weeks and included the following major activities (see Section 8 for details on modifica-tions):

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Initial shutdown and cooldown of the plan Leak rate testing of valves that require the reactor to be pressurized. Control rod friction testing followed by change-out of 10 control rod drives. Parallel with this effort, the reactor was disassembled

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and-prepared for refueling. Implementation of a number of design changes took place shortly after plant shutdown. The mode switch was in refuel most of the time, secondary contain-ment was required, and the~ majority of.ECCS systems remained operable. The "A" low pressure turbine rotor was replaced with a monoblock design. Maintenance on the remainder of the turbine, generator and auxiliary components proceeded concurrently. Mod-ifications to the main control room (MCR) panels were made as a :

result of the detailed control room design review (DCROR).. 'l Installation of the ERFIS computer proceeded which required num-erous signal tapping retests in the MCR panels. These activitie l continued throughout the entire outage. Major design change work such as M0V control circuit rewiring and high speed valve actua-tor modifications began and continued through the outag Refueling operations. This phase included replacement of 136 fuel bundles; twelve control rod blade replacements; four local power range monitor (LPRM) replacements; control rod drive repl-acements; and, fuel sipping and visual examinations. Normal

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post' refueling core testing was. performed at the end of this phas This included control rod friction testing, core verifi-cation and shutdown margin /in-sequence critical testing. Prep-aration for the main station battery discharge tests and a number of design changes that did not affect ECCS operability require-ments were completed. The mode switch was in refuel for the majority of this work (in start-up for the low power physics testing). Secondary containment was required and the majority of ECCS equipment was operable throughout this perio Implementation of design changes and maintenance. This phase included continuance of design changes and modification work; i preventive and corrective maintenance; in-vessel inservice inspection (ISI) of core spray piping, feedwater spargers, jet pump inlet nozzles and annulus access plate; ISI of the reactor L vessel flange and studs. The mode switch was in shutdown for this phase and secondary containment was not require This phase concluded with reactor vessel reassembl System and modification testing. Activities in this phase covered the majority of final testing required to declare sys-tems and equipment operabl Included were the integrated ECCS l

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test, PCIS testing, RPS response time test, control rod scram s testing, reactor vessel cold hydrostatic test and a primary con-l tainment integrated leak rate test (PCILRT).

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Plant recovery and startu The final outage phase included initial plant heatup, reactor startup and main turbine startu Preparations for this phase were extensive. The startup process included various tests required by technical specifications (TS)

that require hot conditions or steam, nuclear instrumentation 1 testing and main turbine generator testing. This phase concluded with placement of the generator on the grid following turbine ]

overspeed testing, j

.. 6.3 Plant Startup Preparations and Activities The inspector reviewed the licensee activities to recover from the outage and prepare plant systems for operations. The inspector reviewed the completion of prerequisites identified on milestone punchlists and startup checklists. Several major tests were witness-ed and results were reviewed to verify that system operability was appropriately demonstrated. System valve lineups were reviewed to verify the adequacy of the licensee administrative controls to assure proper system alignment. The tests and evolutions inspected are listed belo + In-sequence Critical Test + Reactor Startup

+ Scram Time Testing + Low Power Testing

+ Integrated ECCS Test

+ Reactor Hydrostatic Test

+ Integrated Leak Rate Test The inspection of the above events determined that the licensee had detailed procedures and milestone punchlists to adequately control restoration and startup activities, and to verify that startup pre-requisites were satisfactorily accomplished. Procedures and adminis-trative controls were adequately followed. Specific items are dis-cussed further below and in Section In-Sequence Critical Testing l

The licensee performed in-sequence critical testing on March 2, 198 Testing included a shutdown margin (SDM) check and verification of core parameters. Technical specifications (TS) 3.3. A.1 and 4.3. require that the core loading be limited to that which can be made l

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subcritical in the most reactive condition during the operating cycle with the highest worth, operable control rod in its fully withdrawn position and all other operable rods inserted. An additional require-ment is that control rods be withdrawn following a refueling outage i when core alterations were performed to demonstrate a shutdown margin ;

of 0.0025 delta K at any time in the subsequent fuel cycle with the :

highest worth operable control rod fully withdrawn and all other oper- )

able rods inserted. This constitutes the SDM chec .

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! Data collected during the in-sequence critical test supported the SDM i

determination. The inspector reviewed procedures and checklists used during the testing, and verified parameters and observed values of J test results. Additionally, the inspector verified that TS SDM I requirements were me In-sequence testing also provides data for identifying potential reactivity anomalies as well as comparison between the expected and actual critical rod configurations. Data was collected to aid in predicting the expected rod notch inventory. This base data will be used .to generate curves of notches inserted versus exposure. A band will be applied to this curve representing the number of notches equivalent'to 1% delta K/K to indicate the reactivity deviation limi The inspector reviewed data associated with this testing and confirmed licensee calculations. The actual critical rod pattern was close to that predicted and well within allowable deviation. The inspector noted highly professional licensee performance during this testin The inspector had no further questions in this are Ir.tegrated ECCS Test The inspector reviewed the conduct of surveillance procedure OP.4100,

"ECCS Integrated Automatic Initiation Test", which tests the proper response of the emergency core cooling system to automatic start sig-nals concurrent with simulated loss of offsite power. The automatic initiation test is performed by simulating a high drywell pressure and low-low water level and low reactor pressure signal and a concurr-ent low voltage on Buses 3 and 4. Diesels, pumps, motors and valves are checked for starting time, sequence and total KW 1- f. The emerg-ency load is manually applied by starting vital equipa The follow-ing sequence of events occurs with a simultaneous loss of normal power and a high drywell pressure or low-low reactor water level with low reactor pressure:

The voltage condition, sensed on Buses 3 and 4, combined with the ECCS initiation signals, de-energizes Buses 3 and 4 and initiates the diesel generators starting circuits within three seconds. At the same time, the high drywell pressure and low-low reactor water level signals initiate HPCI and RCIC and trip the UPS feeder breakers in Buses 8 and 9. Within thirteen seconds the diesels will accept the following automatic starting loads; diesel auxiliaries, diesel room fans, a-c motor-operated isolation valves, emergency lighting, station service water pumps C and D, and RHR pumps A and Five seconds after diesel generator breaker closure, the remaining two RHR pumps B and C start. Ten seconds after diesel generator breaker closure, both core spray pumps start. After one minute has elapsed, a RBCCW pump starts. The remaining essential loads are operated manually by the operator when required and as the diesel generator capacity per-mits. The performance of plant systems during the test was satisfac-tory.

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The pre-test verification of initial conditions, test personnel per-formance and test control were excellent. The integrated ECCS test provides an indication of the effectiveness and quality of various licensee outage activities including: pre-maintenance planning; main-tenance quality control; post-maintenance testing; surveillance test- n'

ing; equipment / system control; operability determinations; coordina- .

tion; an.1, supervision. The success of this test and the professional-manner in which it was conducted attest to the licensee assurance of quality in these activitie No inadequacies were identifie !

Reactor Hydrostatic Test A cold operational test provides assurance that all vessel boundaries which have been interrupted during a refueling or maintenance outage have.been returned to an operable condition. For such a cold opera-tional test, the reactor pressure vessel is heated above the minimum pressurization temperature (MPT) by means of core decay heat and RHR pump operation. When the MPT requirement has been satisfied, the

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reactor vessel is filled two feet above the head flange and the head vents are shJt. Pressure is then increased to approximately 85 psig and a rapid visual inspection of all pressurized piping, seals, flanges, etc., is conducted. The RHR pumps are stopped, the shutdown cooling lineup secured, and the recirculation pumps started following the 85 psig inspection. Vessel pressure is increa' sed to approximately 500 psig using the control rod drive or condensate systems as a source of pressure. A rapid visual inspection is then conducte Following the successful completion of inspection at 500 psig, the reacter vessel pressure is increased to 1018 psig using the control rod drive system. The cleanup system and/or bottom vessel drains are throttled concurrently with the feeding systems to maintain the desired pressure

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and level. Following repairs by welding on any pressure retaining boundary or components, and at or near the end of each inspection interval, a hot system leakage and hydrostatic pressure test must also be performed. This hot test is done following the cold test and in accordance with routine station startup procedure The inspector reviewed the conduct of the reactor vessel Class I hydrostatic test and noted that the test was completed satisfactory-il Various packing leaks were identified and repaired by the licensee. Extensive system inspections were performed with the sys-tem at test pressure. A thorough inspection by an auxiliary operator

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noted a small weld crack on the "D" main steam line flow restrictor one inch instrument line. This primary pressure boundary flaw was

satisfactorily repaired prior to plant startup. The licensee demon-strated excellent inter-departmental communications during prepara-tions for this tes Punchlists and prerequisites were well-con-trolled and effeci.ively administered.

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6.4 Primary Containment Isolation System (PCIS) Actuations l January 31 - Group III l' On January 31 with the' reactor operating at approximately 84% power, a primary containment isolation system (PCIS) Group III and subse-quent standby gas treatment system (SBGTS) actuation occurred. The actuation, which isolates primary and secondary containment ventila-tion, was initiated by a spike on the "B" reactor building ventila-tion radiation monitor. The isolation was promptly reset and systems were restored to normal operation after plant personnel verified acceptable radiological conditions. System operability requirements were satisfied at all time Investigation found no damaged equip-ment or apparent cause for the spiking problem. However, small spikes were apparent on the monitor-recorder. As a preventive meas-ure', the licensee decided to replace the sensor / converter and was in the process of off-line performance testing of the spare,.when the monitor spiked again and caused a second Group III isolation described belo February 13 - Group III On February 13 with the reactor in the cold shutdown condition, a PCIS Group III and subsequent SBGTS initiation occurred. The actua-tion, which isolates the primary and secondary containment ventila-tion, was initiated by a spike on the "B" reactor building ventila-tion radiation monitor. The isolation was promptly reset and systems were restored to normal operation after plant personnel verified acceptable radiological conditions. System operability requirements were satisfied at all time Investigation found a defective sensor /

converter in the "B" reactor building ventilation radiation monitor system causing intermittent spiking. Following this event, the sensor /

converter'was replaced. The root cause for the sensor / converter fail-ure is under investigatio The PCIS Group III and SBGTS operated as designed and successfully isolated the primary and secondary containment ventilation. A PCIS Group III isolation and SBGTS initiation are the expected result.of a trip of one side of the reactor building ventilation radiation moni-toring system. Prior to the first event, there were no obvious indi-cations of malfunctions or abnormal readings from either the "A" or

"B" reactor building ventilation monitors. During the spikes, the

"A" monitor showed normal readings and, after the event, neither the

"A" or "B" showed any abnormal indications. No surveillance or unusual activities were in progress at or near either the detectors or the panels that hold the electronic Once radiological conditions were determined to be normal, the isola-tions were reset and systems returned to normal operation. After the second event investigation, the sensor / converter failure became detectable and the equipment was subsequently replaced. The licensee

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11 will continue to try and determine the root cause.of the problem and will contact the vendor. The inspector identified no inadequacies and had no further question February 14 - Group III On February 14 with the reactor shutdown and undergoing disassembly, a PCIS Group III actuation ana subsequent SBGTS initiation occurre The Group III isolation was initiated when the reactor steam dryer was transferred to the steam dryer / separator pit. This exposed the refuel floor monitor to above normal radiation levels which tripped the monitor and caused the Group III isolation and SBGTS start. The increased radiation level is normal when the steam dryer is moved through the air to its storage place. However, the maintenance proce-dure that controls the transfer of the steam dryer does not have a step to notify the control room of-the pending move. When the dryer was placed in the dryer / separator pit, radiation levels returned to normal. The isolation was reset and all systems were returned to normal operatio The root cause of this event was an inadequate procedure. The main-tenance procedure used for disassembly of the reactor vessel does not include a step to notify the control room prior to the steam dryer being move Such a step would have alerted the operators and allowed them to pre plan the event and address the isolation when the steam dryer movement was complete. Although the control room was notified of the dryer movement, notification preceeded the Group III isolation by only about a minute. A Group III actuation due to dryer movement on the refuel floor is generally not an unexpected occurrence. How-ever, lack of procedural controls or ample control room notification indicate this was neither a well-communicated nor coordinated evolu-tion. Licensee corrective actions included an appropriate procedure revision to require ample control room notification and anticipation of the expected Group III isolation when moving the dryer assembl The inspector had no further questions related to this even February 23 - Group III On February 23 a PCIS Group III actuation and subsequent SBGTS initia-tion occurred. The PCIS actuation was initiated by a high radiation signal received from the refueling floor radiation monitor when the

" hot end" (high activity level) of a local power range monitor (LPRM)

being transported to the spent fuel pool momentarily came close to the surface of the water. When the LPRM was being transported between the reactor cavity and the spent fuel pool, the safety hook support-ing the LPRM hung up on the lip of the reactor vessel. In order to free the hook, a technician jerked the LPRM unlatching tool cabl This caused the hot end of the detector to momentarily come closer to I the surface of the water. Resulting increased radiation levels tripp-ed the refueling floor monitor and caused the PCIS isolation. The technician performing the evolution misjudged the depth of water I

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c'overing the LPRM and assumed there was sufficient shielding to allow use of the unlatching tool to free the LPRM. Immediately after the cable was jerked, the hot end sank back to its original depth which provided sufficient shielding to decrease the radiation to expected levels. Following verification of normal radiation levels, the isola-tion was reset and the SBGTS.was returned to standb The . licensee temporarily suspended LPRM movement activities and reviewed the event with the involved personnel. Subsequent LPRM acti-vities were performed without inciden The licensee committed to procedure revisions to include specific instructions to maintain shielding during transfer of the LPRM. The procedure will also be modified to. include a precautionary step to remind the technicians of..the potential for increased radiation 1

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levels associated with off normal movements when transporting an exposed LPRM. Revisions will be completed prior to the next refuel-ing outage currently scheduled for September 1990. The licensee also committed to investigate alternate methods and procedures for per-forming this evolutio Although no personnel overexposure occurred and administrative dose limits were not exceeded, radiation levels on the refuel bridge increased significantly and represented a potential personnel hazar Licensee initial reaction to the event was to. consider it relativel routine. Subsequent plant operations review committee (PORC) review of.the event identified several deficiencies and emphasized the poten-tial hazards of the evolution. Licensee control of the evolution appears to have been insufficient. Planned corrective actions ade-quately. address the root cause of the event. Effectiveness of these actions will beLreviewed in routine inspection activitie The inspector had no further questions in this are March 7 - Group III On March 7 a partial PCIS Group III actuation and subsequent "A" SBGTS, initiation occurred. The reactor protection system (RPS) "A"'

motor generated (MG) system was scheduled to be taken out of servic A PCIS Group III actuation would normally occur upon deenergization of the logic circuitr To prevent an- unnecessary isolation from occurring, a lifted lead and jumper (LL & J) was initiated and installed. Actuation of the "A" side of the PCIS Group III logic is provided by two normally energized relays. The relay associated with the reactor building ventilation exhaust high radiation monitor was bypassed by an installed bypass switch. The relay associated with the reactor building refueling floor high radiation monitor required ;

two sets of contacts to be jumpered to prevent actuation. Techni- '

cians developed and implemented a LL & J which only jumpered one set of these contacts. Consequently, removing the RPS MG-A set from service caused a partial Group III actuation and start of the "A" SBGT Subsequently, control room operators conservatively completed

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the isolation and assessed plant conditions. The LL & J was subse-quently revised and correctly implemented. The isolation was reset and the systems returned to normal operation. Licensee corrective actions centered on counseling of appropriate involved personne This occurrence demonstrated poor control of a process designed to !

ensure safety. The LL & J request process involves multiple reviews and independent verifications to ensure proper design and correct implementation. Technicians, engineers, supervisors and operations personnel reviewed the request prior to implementation. All of these reviews failed to identify the inadequacy of the proposed LL & Lack of attention to detail ard inadequate control of the LL & J process were discussed with the licensee. The inspector had no further question .5 Diesel Fuel Oil Analysis On February 16, 1989 the licensee determined that a fuel analysis of the diesel fuel oil storage tank contents had not been performed for the month of January 1989. Technical specification (TS) 4.10. requires monthly sampling of the tank and analysis per ASTM D975-68 Table I. The inspector identified an unresolved issue (88-08-01) in June 1988 pertaining to the licensee's failure to fulfill TS 4.10. requirements. In August 1988, the licensee resolved the issue by expanding the scope of sampling practices to include all ASTM D975-68, Table I specification . A portion of this revised analysis was to be performed onsite with the balance of the analysis being performed offsite. On February 16, 1989, while reviewing the results of the offsite portion of the February analysis, the licensee deter-mined that a January sample had not been sent offsite for analysi At the time of the event, the fuel oil sampling and analysis require-ments were being controlled via a monthly surveillance list. A written procedure was being prepared to control the expanded sampling activity, but was still undergoing review. It had not yet been approved for use at the time the January sample analysis was omitte There was a lack of specific administrative controls and procedures needed to assure that the sample analysis was completed on a regular monthly basis. Additionally, the surveillance test list in use at the time of the event was not sufficiently descriptive to assure that the sample was adequately processed after being obtained. The Chem-istry Department did not provide adequate interim controls or associ-ated training to Chemistry personnel to ensure all expanded sampling requirements were met before the formal procedure was issue The fuel oil samples that were sent offsite in December 1988 and February 1989 were found to be in compliance with ASTM D975-68 Table I limits. Additionally, onsite samples analyzed on January 2 and 19, 1989 were found satisfactory for critical parameters (viscosity, water and sediment). Therefore, there is reasonable

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assurance that all applicable ASTM specifications for the diesel fuel oil were met at the time of the event and there was no adverse safety l

impac Subsequent to the event, the licensee approved and issued a procedure H for performing the required sampling. Appropriate personnel received training that specifically addressed necessary actions to ensure correct. fuel oil sampling. Additionally, the surveillance test list

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was revised to identify the-type analysis required and to require supervisory review of completed analyses. These actions appear to be sufficient to prevent recurrence. However,.the inspector noted that previous licensee corrective actions in response to unresolved item- i 88-08-01 were not sufficient to ensure required oil analysis was !

completed. Although the sampling program was revised in a timely manner, formal procedural documentation of the upgraded program was deferred approximately six months until January 5,1989 when Revision

.11 of OP 4613 was issued. This delay appears excessive. Although interim measures were developed and implemented to control the ;

i program, they were informal and generally undocumente .6 Switchgear Room Fire Suppression System Actuation On March 3, 1989, after control room operators started the "0" RHR pump, a ground fault on Bus 1 was indicated and the control room Pyrotronics panel alarmed, indicating the west switchgear room Pyrotronics' panel had actuated. About 30 secnnds later, an inspec-tion of the west switchgear room Pyrotronics panel indicated that the first, second, and third detectors were actuate Shortly after this inspection, the carbon dioxide (CO2) fire suppression system initiated. The CO2 discharge continued for approximately 30 minute About ten minutes after initiation, ventilation was established in the 248' level of the Administration Building corridor due to low oxygen levels (approximately 1994) in the switchgear room access corridor. Shortly thereafter, oxygen levels returned to normal (approximately 2196). About fifteen mirytes after initiation, oxygen levels in the cable vault room were found to be normal. At that time oxygen levels in the control room were also found to be norma Approximately thirty minutes after the CO2 initiation, the control room toxic gas monitoring (TGM) system initiated causing isolation of control room ventilation and actuation of the control room breathing air system. Operators subsequently donned self-contained breathing apparatus (SCBA). Within ten minutes oxygen levels in the control room were determined to be normal and the operators removed the SCBAs. After a thirty minute soak, entry into the west switchgear l room determined that no fire existed. The switchgear rooms were subsequently ventilated to remove the CO !

The licensee determined that the most probable cause of the suppres- ;

sion system initiation was a ground fault on Bus The fault caused 1 the power resistors in the ground fault circuit to overheat resulting !

in a release of ionized particles (dust build-up on the resistors).

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The particles caused activation of ionization detectors in the k, vicinity of the resistor The ground fault was subsequently traced to the'"B" service water pum Post-initiation inspection of the west switchgear room found the two fire. doors that connect to the east switchgear room cracked ope These are separate fire zones with distinct detection and suppression systems. The east and west switchgear rooms are divided by a fire 1

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wall. The rooms are interconnected by two doors, both of which'open into the east room...During normal operation, air flow is maintained from each room by a fan which exhausts to outside of the buildin Upon a CO2 initiation, the fans will continue to operate for five minutes to allow CO2 to fill the room and vent displaced air from the room. At the end of five minutes the fans turn off and a fire damper closes off the exhaust. However, an actuation in one room does not affect the suppression system or fan in the other room. In this case, the east switchgear roo'm exhaust fan continued to operat Because the fire doors were cracked open, the differential pressure between the rooms caused by the CO2 discharge allowed CO2 to vent to the east room and subsequently exhaust to outside of the buildin This sequence could diminish the effectiveness of the west room C02 system.and in this case resulted in a lower than expected CO2 con-centration in the west room. The licensee postulated that, had there actually been a fire in the west switchgear room, products of combus-tion would have been carried over into the east room. This would have resulted in an actuation of the east CO2 suppression syste This actuation would have eliminated the differential pressure problem between the two rooms and closed the doors. Since, the CO2 systems discharge for approximately 30 minutes, and the double actuations would most likely occur in the early part of the event, both rooms would have had an acceptable CO2 concentratio The root cause of this deficiency was failure of the fire door latches due to poor maintenanc The licensee determined that the most probable cause of the TGM initi-ation was control room ventilation system intake of the CO2 that was being exhausted from the east switchgear room. The control room vent-ilation supply intake is in the same general vicinity as the east room ventilation exhaust. Control room TGM actuation on high CO2 levels due to post-initiation venting of the switchgear room also ,

occurred on June 30, 1987 and September 23, 198 '

Licensee _immediate response to this event included:

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Normal response to switchgear room suppression system actuatio Normal response to TGM actuatio Repair and replacement of switchgear room connecting fire door latches.

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Addition of door checks to operator rounds sheet Long term corrective actions include:

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Revising' administrative and operating fire procedures to require that the control room ventilation system and toxic gas sample points'be placed in the recirculation mode upon an actuation of a CO2 suppression syste . Including the switchgear room door' latches into the vital fire barrier surveillance procedure to be periodically inspected for proper operatio Evaluating the TGM system to ensure that it is satisfying its original design requirement which is that controlled venting of CO2 from the cable vault or switchgear rooms should not initiate the TG ' Including the grounding resistors as a preventive maintenance ite Providing additional training to inform personnel that certain activities have the potential of causing smoke detectors to go into an alarm conditio Findings The inspector observed operator and fire brigade response to this event. Activities were well-coordinated and professionally execute Operator responses to both the CO2 and TGM actuations were conserva-tive and controlle The. inspector noted that the issue of CO2 infusion into the control room environment following a switchgear room suppression system actu-ation had previously been communicated to the licensee as unresolved

. item 87-12-01. This item resulted from the June 30, 1987 event. The inspector revisited this issue with the licensee following the September 23, 1988 even Licensee corrective actions to resolve this issue were inadequate. The licensee revised OP'2186, " Fire Suppression Systems", to direct control room operators to place the control room HVAC and TGM sample points to the recirculation mode prior to venting CO2 from the switchgear rooms or cable vault. A more appropriate revision would have been to place the control HVAC p^ and TGM sample points to the " recirculation" mode upon initiation of a carbon dioxide fire suppression system. Additionally, the revision should also have been incorporated in OP 3020, " Fire Brigade and Fire Fighting".

Current licensee corrective actions, including procedure revisions and system design reviews, should adequately address preventing recurrence of TGM actuations upon CO2 system discharges. The inspector had no further questions regarding this even _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - - _ _ _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ . _ _ .

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6.7 Unusual Event - Reactor Water Level Decrease On March 9, 1989 the licensee experienced an unanticipated decrease in reactor vessel water level. The reactor was in a shutdown and cooldown condition with the vessel open for a refueling outage. Ini-tial vessel water level was 290 inches above top of active fuel (TAF).

In-vessel in-service inspection (ISI) was in progress. The "A" RHR loop was out of service for various maintenance activities. The "B" RHR loop was providing reactor shutdown cooling. The "A" RHR loop contains pumps "A" and "C" and the "B" RHR loop contains pumps "B" and "D". As shown in the simplified system sketch (See Figure 1),

two shutdown cooling loops share a common supply line from the reac-tor recirculation system, with the unused loop being isolated by the individual pump shutdown cooling suction valves (RHR-15A-D). Thus, at the time of the event RHR-15A and C were shu To support ongoing maintenance activities, the circuit breakers for the idle "A" and "C" RHR pumps were opened and racked down and their control circuits were de-energize Upon de-energizing the control circuits, RHR pump logic opened the pump minimum flow bypass valve in the "A" RHR loop (RHR-16A). This valve normally protects the "A" and

"C" pumps from a potential dead head condition. Subsequently, the breakers for the "A" and "C" RHR pump shutdown cooling suction valves (RHR 15A and C) were released for maintenance to allow for electrical work on the valve operators. At 10:55 p.m. on March 4, maintenance personnel manually stroked open RHR 15A and C to set limit switche When these valves were opened, a gravity drain path was created from the reactor vessel to the suppression chamber., This path was through the common supply valves from the reactor vessel that were open to support "B" loop operation (RHR 17 and 18) through RHR 15A and C, and then through the open "A" RHR loop minimum flow bypass valve (RHR-16A) which directs flow to the suppression chamber. At 11:00 p.m., the control room was notified by personnel working on the refuel floor of a drop in reactor vessel level of approximately 18 inches from its initial 290-inch level. Control room personnel initially attributed the drop in level to be due to drained portions of the "A" RHR loop refilling upon opening RHR-15A and C and did not expect any further decrease in vessel leve At 11:15 p.m. the control room was notified again by refuel floor personnel that level had dropped an additional 18 inches. At this point refuel floor personnel performing in-vessel ISI evacuated the j reactor cavity. At 11:47 p.m. control room operators identified the leakage pat However, because the "A" and "C" RHR pump motor brea-kers were still racked out, control circuitry did not allow remote closure of RHR-16A. An operator subsequently closed the manual isola-tion valves for RHR-16A (RHR-69A and C). This action isolated the leak path and terminated the vessel level decrease. Level was subse-quently restored to normal using the control rod drive (CRD) syste Total level decrease was 72 inches over an approximate 54-minute time frame. Total volume transferred from the vessel to the suppression

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pool was approximately 10,300 gallons. Upon review of the event, the operators declared an Unusual Event (UE) at 12:40 a.m. on March 1 The UE was terminated at the same time due to isolation of the leak path and vessel level restoratio Licensee analysis of the event concluded that the root cause was per-sonnel error. Plant operators did not anticipate that racking out RHR pump circuit breakers would result in the corresponding minimum flow valve (RHR-16A) opening. Additionally, operator review of "A" RHR loop status prior to releasing RHR-15A and C for maintenance did not identify that RHR-16A was open. This valve indicated open on the control room panel but was overlooke Licensee long term corrective action includes revision of OP 2124,

" Residual Heat Removal System", to provide a precaution that empha-sizes the fact that the corresponding minimum flow valve will open when an RHR pump breaker is opened and racked dow In addition, an operator aid will be installed at the RHR pump breaker cabinets which will direct operators to inform the control room of the pending mini-mum flow valve "open" signal prior to racking down RHR pump breaker Currently, licensee procedures require operators to isolate potential drain paths on the shutdown cooling loop in service by closing the associated valves (including the minimum flow bypass valve) and open-ing their breakers to assure isolatio To prevent recurrence of this event, the licensee will expand procedures to require closure of the RHR-15 valves in the idle RHR loop and opening their breaker If any activity would require opening these idle loop valves, the isolation boundary would be moved downstream of the idle pumps by closing all other potential draindown paths, including the idle loop minimum flow bypass valve, and opening the corresponding breaker Findings The inadvertent draining of the reactor vessel was relatively slow and afforded the operators ample time to correct the situatio Even without any operator action, the draindown would have been terminated by automatic initiation of the primary containment isolation system (PCIS) upon reaching a level of 127". At this level, PCIS initiates closure of the two isolation valves on the common RHR system supply from the reactor recirculation system (RHR-17 and 18). Therefore, the operator actiun that was taken and the backup PCIS function that l was available provided ample margin over the Vermont Yankee safety l limit of 12" above TAF. Additionally, makeup systems, including the

"B" RHR loop and CRD system, were available to increase vessel water inventor Inspector review of the event included interviews, log review, pro-cedure reviews, and system walkdowns. The inspector noted that, although shift control roon, operators had worked overtime during the outage, overtime was not excessive, and was within licensee and NRC guidelines. Operator fatigue was apparently not a causal factor for )

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l the event. The inspector determined that the operators are acutely aware of the potential for vessel draindown during shutdown condi-tions. They are generally very familiar with all the possible drain-ing pathways. In this event, the inspector determined that operators took several actions to ensure vessel draindown was avoided and were generally proactive in control of maintenance activities. Overlook-ing the open RHR-16A valve or failing to recognize the significance of this open valve appears to have been a momentary lapse in atten-tion to detail. Planned procedural changes, although not a substi-tute for vigilant operators, should enhance RHR system administrative controls and aid in preventing recurrence of this event. The inspec-tor had no further questions in this are .8 Partial ECCS Actuation On March 10, 1989, as a result of repowering the "B" ECCS analog trip cabinet, a spurious low-low reactor water level signal was generated in the "B" ECCS logic system. This resulted in the following actions:

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Initiation signals to high pressure cooling injection (HPCI) and reactor core isolation cooling (RCIC) system Trip of the "B" RHR service water pum Trip of the "A" uninterruptible power supply (UPS).

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Startup of the "B" diesel generato The initiation signals for HPCI and RCIC were immediately reset as well as the "B" RHR service water pump. The unloaded diesel genera-tor was secure Power to the "A" UPS was promptly restored per plant procedures. No other safety system actuations occurred during the event and no in,iection to the reactor vessel occurre At the time of the actuation, modifications were being performed on the analog trip cabinet. The cabinet was in the process of being repowered when the spurious signal was generated. As the circuit cards within the cabinet were simultaneously powered up, some of the transmitter cards saw a temporary " low" process signal and momentar-ily cycled their trip relay generating a false signa In this event, the analog trip cards associated with level transmitters 2-3-728, and 72D were responsible for the false initiation signa Usually the licensee powers the ECCS analog trip cabinets by removing all trip cards prior to restoring power. Once powered, each cabinet would then have the respective circuit cards singularly installe This undocumented procedure was normally followed by plant instru-mentation and control department (I&C) personnel who maintain and service these cabinets. Because this process was undocumented, it was not widely known by other plant discipline Consequently, when I

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maintenance and operations personnel restored the cabinet, the pre-ferred method was not used. These personnel were unaware of any >

special cabinet startup requirement Findings l

This event was caused by licensee failure to have an authorized and documented procedure to control startup operation of.the ECCS analog

'3 trip. cabinets. Reliance on informal processes for control of plant equipment is not a substitute for formally documented, reviewed and.

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approved procedures. Additionally, closer inter-departmental coordi- '

nation when-performing unfamil_iar operations could possibly have prevented this occurrence._ Long term licensee corrective actions, including procedure development and equipment information tags, appear to adequately address this event. Additional licensee review of the potential for other undocumented control procedures.is also.

f warranted. The inspector had no further questions in this are .9 Leaking Fuel Inspection report 88-06 identified an increase in offgas system . I radiation levels beginning on March 21, 1988. The increased radia-tion levels were indicative of a small fuel pin lea Release rates fluctuated throughout the operating cycle in response to power changes'and rod pattern adjustments. At all times the release rate remained well below the TS 3.8.K.1 limit of 0.16 C1/sec. Reactor i vessel isotopics for dose equivalent I-131 also remained well below the TS 3.6.B.1 limit of 1.1 uCi/gm. Environmental release rates-calculated in accordance with the Offside Dose Calculation Manual (0DCM) remained far below the TS 3.8.E.1 limits. Licensee analysis of various data, including offgas flux tilt monitor readings, narrowed the possible bundle selection for sipping during the outag Fuel sipping operations were conducted on February 17,19 and 20, 1989 to identify the leaking fuel bundles. Forty bundles previously selected by the- reactor engineering (RE) department were sipped. Two fuel bundles, LYC-235 and LYC-175, were identified as leaking. The failed bundles, which were scheduled to be permanently offloaded, were placed in storage in the spent fuel pool. Subsequently, the licensee employed contractor personnel to perform visual examinations of twelve fuel bundles, including the two identified failures. The examination was performed to identify possible fuel failure modes, inspect the general condition of the fuel, and to obtain fuel pin corrosion layer scrapings. The failed pin in LYC-175 was easily identified. Although the failure mechanism could not be character-ized, crud induced localized corrosion (CILC) was not determined to be a factor. The failure in LYC-235 was more difficult to verify and only a suspected pin could be identifie Visual inspection results, corrosion layer sample analyses, and photographic examinations will be reviewed by the fuel manufacturer to confirm failure mechanisms and provide recommendations to the

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. licensee. The licensee is working closely with the fuel vendor to improve fuel performance. The licensee exhibited technical compe-tence and excellent analysis in response to the failed fuel. Close interaction.with the fuel vendor and other branches of the industry is aiding in problem analysis. Fuel sipping operations and visual examinations were well-coordinated and professionally execute Licensee continuing actions will be reviewed during routine inspec-tions. The inspector identified no deficiencies in this are .10 Unusual Event - Torus Water Level Increase On April 9, 1989, while operating at 13% power during startup from the outage, the licensea declared an Unusual Event (UE) - terminated when torus water volume exceeded the TS 3.7.A.1.f. limit of 70,000 cubic feet. The licensee was performing several evolutions at the time including main turbine warmup, drywell inerting, and high press-ure coolant injection (HPCI) system post-maintenance testing. HPCI testing increases torus volume and torus water temperature due to the turbine exhaust steam directed to the torus. For extended HPCI runs, torus level and temperature are usually controlled using the RHR system in the torus cooling mode. HPCI was run from 10:40 to 11:00 a.m. and then started again at 12:35 p.m. Subsequently,.

operators established a small differential pressure (dp) between the drywell and torus in order to facilitate drywell atmosphere samplin Establishing the dp caused water to be forced out of the drywell down-comers and into the torus. With torus volume already' elevated due j to HPCI testing, the increase due to the dp caused torus volume to exceed 70,000 cubic fee ;

Operators took prompt action in response to the excessive torus water j level. HPCI was secured and the "A" RHR loop was used to transfer '

approximately 8,700 gallons from the torus to radwaste. Torus volume j returned to the allowed band at 2:20 Findings f

Licensee actions in response to the high torus water level were j prompt and effective. Licensee review and analysis of the event i determined that a TS limit had been exceeded. The licensee concluded i that the necessary action for this condition would have been to imme- !

diately commence a controlled reactor shutdown and be in cold shut-down in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Because the condition was corrected prior to this determination, an actual reactor shutdown was not commence Some 1 confusion existed in the licensee review of TS 3.7.A.1.f and 3.7. i requirement Formal internal clarification of these requirements is i necessary to prevent future interpretation problem The event appears to have been at least partially caused by a lack of 1 attention to detail. Operators are thoroughly familiar with the effects on torus water level of establishing a drywell-to-torus dp and of running HPC The effect of the combination of these activi-

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l 22 ties was not adequately anticipated. Overall control of plant start-up activities was good. Complex evolutions were performed well and i generally were carefully coordinated. However, in this instance i relatively routine evolutions were performed in an unusual sequence without adequately anticipating the overall effect on plant condi-tions. Discussions with licensee management indicated that correc-tive actions adequately addressed the issu The inspector had no further questions in this are .

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6.11 Event Notifications ;

The licensee continued to demonstrate difficulty in adequately ful-filling event notification requirements. Unresolved item 88-08-05 was opened in July 1988.to address this weakness. Other lapses have ;

occurred since that time. Most recently, several events occurring ~

during the early part of the outage were initially considered by the i licensee to be not reportable. Only after multiple meetings with the resident staff did the licensee formulate adequate internal guidance for event reporting. Although the majority had minor or no safety significance, failure to report these eventss ' demonstrated an inabil - ;

ity to effectively resolve an administrative weaknes Licensee corr-ective actions prior to the outage were only partially effective in addressing tN outstanding unresolved issue. Failure to fully rec-tify the situation is indicative of a less than fully effective corr-ective action progra Following the first few events during the outage, the licensee devel-oped an interim position on event reporting that was overly conserva-tive. As a result, several unnecessary notifications were made for events that did not meet reporting t', ashold Reporting guidance was refined during this period to better identify and define what constitutes the' critical elements of a reportable even Progress in this area was evident towards the end of the outage. Events were being properly identified, classified and reporte Unresolved item 88-08-05 will remain open pending licensee demonstration of consist-ency and correctness of event identification and notlfication. This issue will be reviewed during routine inspection activitie . Maintenance / Surveillance 7.1 Snubber failure On February 13 during refueling outage surveil.*no testing per TS 4.6.I.1, shock suppressor MS-35 on Main Steam "D" piping was found with no visible fluid in its sight glass. When functionally tested, the snubber did not exhibit acceptable lock-up and bleed rates. The tests determined that the snubber would not have provided restraint during a seismic event or transien Technical specification section 3.6.I.1 requires a safety-related snubber to be operable whenever its supported o stem is required to be operable. The MS-35 shock supp-ressor belongs to a group of 24 out of 46 safety related snubbers

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which are classified as inaccessible during reactor operation. A {

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visual inspection of the inaccessible snubbers is accomplished after .

shutdown and prior to startup from a refueling outage. The MS-35 !

. snubber is a 2.5" x 5" Grinnel shock suppresso l c

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Snubbers are. designed to restrain pipe motions under dynamic loads, .l as might occur during an tarthquake or severe transient, while allow- 1 ing. thermal motion during normal operation. .The consequence of an inoperable snubber is an increase in the probability of structural damage to pip 1ng as a result of an event initiating dynamic load The licensee performed an engineering evaluation of the piping and 1 supports in 'the area to ensure no detrimental effects resulted due to i MS-35'becoming inoperable during the previous operating period. The i evaluation was completed prior to plant startup. No damage or detri-mental effects were observe Snubber MS-35 was removed from service, inspected, rebuilt, function- i ally tested and subsequently reinstalled in the system. The root i cause for the fluid loss was determined to be a worn rod bushin l The worn rod bushing induced a rod shaft seal leak. Since the 'i snubber piston rod showed no signs of metallic scouring or abrasion, the seal leak is attributed to normal service wear of the bushin Excessive wear of the bushing is normally identified during a visual l inspection by a loss of fluid level in the reservoir prior to total i fluid los Based on this the licensee determined that no additional inspection was necessar .Because MS-35 failed to pass the visual examination, the surveillance i inspection interval per TS 4.6.I.1 will be decreased to 12 months +/-

25% if accessibility for longer than 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months becomes available. The i inspector identified no deficiencies and had no further question ,

7.2 Local Leak Rate Testing During performance of leak rate testing for the outage, liquid rad-waste (LRW) valves LRW-83, LRW-94 and LRW-95, primary containment atmospheric control (PCAC) '/alves PCAC-8, 9, 10, 23 and PCAC-6, 7, 6A, 6B, 7A, 78, containmen; air compressor discharge check valve l CA-89C, and feedwater check valve FDW-96A were found to have seat i leakage above that permitted by Technical Specification Section 4 3.7.A.4. The PCAC valves are tested in the groups listed. The i

. measured leakages for the valves were:

Penetration X-18 LRW-83 10.0 lbs. Mass Per Hour j Penetration X-19 LRW-94 0.856 Lbs. Mass Per Hour L

Penetration X-19 LRW-95 5.33 lbs. Mass Per Hour ,

Penetration X-22 CA-89C Could Not Pressurize Penetration X-25/218 PCAC-6,7,6A, SB,7A,7B >25.12 Lbs. Mass Per Hour Penetration X-26 PCAC-8,9,10, 23 3.295 lbs. Mass Per Hour Penetration X-9B FDW-96A Could Not Pressurize

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Allowable single' valve leakage is administrative 1y limited to 0.522 pounds mass per hou "

For penetrations X-18'and X-22, a second containment isolation valve

. in the same penetration was tested that met the criteria. Based on L this, the actual penetration leakage would have been no greater than the smaller of the two valve leakages. For penetration X-19, both isolation valves exceeded the single valve acceptance criteri Therefore, the penetration minimum pathway leakage was 0.856 pounds L mass per hour. For penetration X-98, the valve that is tested

!= (FDW-96A) for the two valve penetration failed. The other valve is exempted from testing. For the groups of PCAC valves, the licensee believes that one of the valves in each group is causing the failur The licensee performed maintenance on failed valves to correct the condition and determine the root cause of failures. Results of these efforts will be documented in the primary containment integrated leak rate test (PCILRT) repor The combination of the valve leakage results detailed above culmi-nated in a failure of both the maximum and minimum pathway leakage allowed by 10 CFR 50 Appendix J. The licensee calculates total penetration leakage using the maximum pathway leakage method (summing the Type B leakage and the largest Type C for each penetration). Due to the number of valve failures, and considering. maximum pathway leakage, the applicable limit was exceede With the exception of the PCAC valve groups and FDW-96A, calculating total-penetration leakage using the minimum pathway leakage method (the sum of the Type B and the smaller of the Type C) yielded a total penetration leakage below the allowable limits. (Note: The leakage from the PCAC Groups was'not considered in the calculation of minimum pathway leakage since the source of the leakage was not identifie Also, since no data existed for the second feedwater isolation valve, minimum pathway leakage was assumed to be exceeded.) Even though valve FDW-96A could not be pressurized, the licensee reasoned that minimum pathway leakage would probably not be affected due to the following:

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The inboard isolation valve FDW-28B, even though not tested, will provide an isolation function in combination with FDW-96 There is reasonable assurance that, with the exception of a feedwater line break (in the same line as FDW-96A), there would have been enough time for the motor-operated valves at the discharge of the high pressure feedwater heaters to be closed before there was any escape of containment atmospher The final calculated values for both minimum and maximum pathway ,

leakage will be included in the PCILRT report approximately 90 days '

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Findings Failures of the LRW valves (83, 94 and 95) were a direct repeat of 1987 failures of these valves (see LER 87-07). Contrary to the licen-see assertion in LER 89-07, valve CA-89C failed leak rate testing in 1984 (see LER 84-11 Revision 2). Some combination of PCAC valves has failed in 1983, 1984, 1985 and again in 1989. These repetitive valve failures indicate potentially inadequate root cause failure analysis, ineffective corrective maintenance or design application weaknesse In the case of FDW-96A, licensee developed corrective action plans to minimize or prevent recurrence have proven to be ineffectiv The inspector noted a potential deficiency in the licensee method of assigning leakage rates to individual valves when tested in group The as-found total leakage through a group is divided by the number of valves in the group and that value is assigned to each of the valves. This is potentially non-conservative and may result in not identifying valves that fail to meet the TS-required leakage limi As an example, the reactor building-to-torus vacuum breaker (SC-11 and 12) is tested as an assembly with test pressure applied between the butterfly and check valve For the 1989 test, SB-11A and 12A exhibited a leak rate of 0.867 lbm/hr. This value is greater than the single valve acceptance criteria of 0.522 lbm/hr, but by proce-dure the leakage is equally applied to both valves resulting in 0.434 lbm/hr per valve. In fact, one of the valves may be responsible for the majority of the leakage. Subsequent repair and testing of one or both of the valves may indicate that one of the valves contributed more than half of the combined leak rate. However, no procedural mechanism exists to review subsequent testing data to determine potential deportability if a contribution of a valve to combined leakage was greater than 0.522 lbm/hr. The licensee agreed to review this potential deficienc Additionally, the inspector noted minor deficiencies in the licensee method for computing minimum pathway leakag These errors were promptly corrected and the inspector had no further question Notwithstanding the noted deficiencies, the inspector observed that the licensee leak rate testing program was well planned, well-coordi-nated and professionally conducted. Cognizant personnel are very knowledgeable of requirements and test performance parameter .3 Containment Integrated Leak Rate Test (CILRT)

CILRT Observations and Procedure Review The licensee conducted the containment integrated leak rate test on March 30-31, 1989. The inspector witnessed various portions of the test, reviewed various records, r,d held discussions with licensee personnel to verify that: the test was performed in accordance with the most recent version of an approved procedure; test instruments-tion was within calibration; stabilization was observed prior to l

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i commencing the leakage rate measurement; the pressurization t.urce l was isolated from containment and vented during the test; plant para- '

meters were recorded as required; the test log was properly main-tained; and a supplemental test was conducted for sufficient duration to accurately establish the change in leak rat The inspector reviewed licensee procedure OP 4029, " Type A - Primary Containment Integrated Leak Rate Testing," Revision 4. The licensee uses the absolute method to determine the mass in containment and mass point analysis to determine the leakage rate. The process compu-ter is used for the mass calculations and a vendor off-line program is used to calculate the linear least squares fit of the mass calcu-lations and the containment leakage rat During the procedure review, the inspector noted that temperature elements (TE) TE 1-158-8.1 and TE 1-158-8.2 (computre points M012 and M013 respectively) each represented a volume fractici of approxi-mately 14 percent. AN#'/ANS-56.8, " Containment System leakage Testing Requirements," requires that no one temperature sensor have a volume fraction greater than ten percent during the test. Also, it was noted that the stabilization criteria were taken from BN-TOP-1, " Testing Criteria for Integrated Leakage Rate Testing of Primary Containment Structures for Nuclear Power Plants," although it was not listed as a reference in the licensee procedure. Through discussion, the inspec-tor noted the licensee was aware of these deficiencies. During the test, two other deficiencies were identified. First, the procedure prerequisite list of lif ted leads and jumpers to defeat the high dry- !

well pressure scrams and isolations was inadequate in that the core spray (CS) pumps and the "A" and "C" residual heat removal (RHR)

pumps started on a high drywell pressure signal during containment pressurization. Second, Appendix E, " Calculation of Test Flow," of the procedure was unclear and/or unnecessary as it did not take into account that the superimposed flow was throttled at atmospheric pressure. A separate calculation was subsequently performed to deter-mine the established test flow in weight percent per day (wt%/ day).

The licensee indicated that these deficiencies would be addressed, including the possibility of adding another TE in the containment head area, during future program / procedure upgrades. The inspector concluded that these procedure deficier.cies did not impact the results of the CILRT conducted March 30-31, 198 CILRT Chronology March 29, 1989 2337 Commenced containment pressurizatio Both CS and the "A" and "C" RHR pumps start on high drywell pressure (trip setpoint less than or equal 2.5 psig).

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l March 30, 1989 0350 Completed an inspection at 30 psig. No leaks foun Containment pressure at 120.60 in. Hg. Air supply isolation valves shu Commenced stabilization perio Restarted stabilization due to shift turnove Repressurized to 120.59 in. Hg. Pressure had dropped to 11 in. Hg during stabilization due to high initial supply air temperatur Stabilization tempers'.ure requirements me i 1305 Commenced depressurizing air supply lin Completed venting air supply lin Commenced start of 24-hour CILR March 31, 1989 !

1157 Process computer alarm due to a problem with the computer reference voltage power suppl Restored process compute Completed 24-hour tes Commenced verification test with a superimposed leak of SCF Completed verification tes Commenced depressurizing the containmen CILRT Results Prior to the process computer problem noted above, the measured leak-age rate remained fairly constant for approximately five hours with a 95% upper confidence limit (UCL) leakage rate of .527 wt%/ day at 10:19 a.m. The acceptance criteria is .60 wt%/ day. The measured leak-age rates at 11:20 a.m. and 12:01 p.m. (.544 and .567 wt%/ day respec- .

tively) increased due to the problem with the process computer. The i licensee initially thought there was an increase in actual leakage; however, a search for leaks had negative results and the licensee noted that the changes in computer mass / pressure data did not corres-pond to the local readings taken at the Mensor pressure indicator _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ - _ _ _ _

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l A verification test lasting about five hours was conducted after the process computer was restored. The superimposed leak rate was 6 SCFM (.421 wt%/ day) The measured leakage rate using the average of the last two hours of the verification test was .932 wt%/ da Due to the bad data at the end of the CILRT, the licensee analyzed the effect of moving back the test start time in order to determine the leakage rate using a full 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months worth of data. The start point for this calculation, 10:20 a.m., was selected based on the earliest time that the stabilization criteria were met. The calculated 95%UCL leakage rate M ng the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months data was .51 wt%/ day. However, by doing this the licensee used about three and a half hours of data during which the air supply was isolated from containment but not vented as require At the time of the inspection, the licensee had only compared the results of this later leakage rate to the verification test data. In this case the CILRT measured leakage rate and the verification test leakage rate minus the superimposed flow were within 1%. The inspec-tor noted, however, that the leakage rate originally measured through the twenty-one hours of good data would have also been within the required acceptance criteria of 25% of the verification test leakage rate minus the superimposed flo Although the inspector acknowledged that the available CILRT data indicated the leakage rate met the acceptance criteria of .60 La, the inspector questioned the acceptability of either using twenty-one hours of valid data or the data without the air supply vented. The licensee is still evaluating the test results; however, the licensee has indicated that its position would be that a 24-hour CILRT was performed, albeit there were only 21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months of good data, and that the verification test and the results from backing up the 24-hour period confirm the validity of the measured leakage rate. This item is unresolved pending NRC review of the completed CILRT test report (89-02-01).

The inspector also reviewed the CILRT required corrections for level changes and/or penetrations not in the normal lineup. The calculated correction was .0042 wt%/ day. The inspector noted that this correc- !

tion would have no significant impact on the calculated leakag "As-Found" CILRT Results i

The inspector noted that the licensee had revised its procedure to include a determination and assessment of the "as found" state of containment. The procedure requires that the difference between the minimum pathway leakage rates before and after repairs to penetra-tions/ valves be added to the CILRT leakage rate and compared to the acceptance criteria of .75 La. The results of this evaluation are to be included in the CILRT test report submitted to the NR _____ __-_ __________-_ _-______ _ _ -

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Based on a review of LER 89-07, "1989 Appendix J Type B and C Failure Due to Seat Leakage," and discussions with licensee personnel concern-ing repairs made, the inspector noted that there appears to be only !

one affected penetration (X-98, "B" feedwater line). In the LER the -

licensee conservatively-assumed that the minimum pathway leakage was exceeded as a result of leakage through feedwater check valve FDW-96 However, the inspector found that the licensee had not completed its- )

evaluation of this penetration and its impact on the as found CILRT results. This evaluation includes the determination of the root cause of the valve failure, corrective actions, and the fact that the in-board valve is exempt from testing. The inspector noted that the licensee is also reconsidering an NRC letter dated June 6,1987, which indicated that no action was necessary at the time with respect to adding Type B and C leak test results into the total containment leak-age determination pending NRC actions to revise 10 CFR 50, Appendix J. The results of the licensee evaluation of penetration X-9B and the impact on the as found condition of containment will be consid-ered during the review of the CILRT test repor In related discussions, the inspector questioned the licensee method of calculating minimum pathway leakage on multi-valve penetration For example (assuming no maintenance or other activity which can de-termine individual valve leak rates), on a penetration with parallel inboard isolation valves in series with parallel outboard isolation valves which are tested simultaneously by pressurizing between the inboard and outboard valves, the licensee divides the total leakage by the four valves. IE Information Notice No. 85-71,

'" Containment Integrated Leak Rate Tests," indicates that the minimum 4 pathway leakage would be one-half the leakage rate for in-series ,

valves tested simultaneously by pressurizing between the valves and l the combined leakage rate for valves tested in parallel. Based on 1 this guidance, the inspector concluded that, for the example above, the minimum pathway leakage would be one half the leakage rate. This is logical because the leakage could be through only one of the in-board and only one of the outboard isolation valves. The licensee acknowledged the inspector's comments; however, the licensee believes additional guidance is needed in this area. The licensee also indica-ted this area would be revisited during preparation of the CILRT repor .4 Electrical Buswork Insulation Degradation During maintenance to a breaker in non-safety electrical bus SB in January 1989, the licensee noted a deteriorated condition of the NORYL buswork insulation. These are ir:sulating sleeves which cover the-main bus bars. The sleeves are a high temperature thermoplastic which provides electrical insulation for protection from possible phase-to phase arcing between main bus bars. Although not an immedi-ate problem, minor cracking or splitting of these sleeves could even-tually lead to a safety hazard. If degradation of the sleeving ex-posed sufficient bus bar area, flash-over arcing could occur. The l' ,'

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potential for. material failures has' been previously identified by the equipment vendor and disseminated to the industry via instruction and service advice letters. Vendor investigations.have shown that the NORYL, while normally stable and suitable for this application, may undergo stress cracking if significant stresses and any of several petroleum based greases, plasticizer, paint thinners,_ industrial cleaning fluids', or chemical contaminants are present. The stresses may be heat, vibration, or fabrication induce Chemical contamina-tion may result from cleaning.or maintenance involving buswork conn-ections. Service age may also be a factor in deterioratio Based upon the condition of the 58 bus, the licensee determined that inspections of the other 4 kilovolt (KV) buswo'rks were warrante Inspections were coordinated with outage plant conditions, equipment availability and equipment operability requirements. Inspection results showed little cracking of the NORYL insulation on the safety-related #3 and #4 busworks. Significant deterioration was found on portions of non-safety #2 busworks. All areas of busworks with crack-ing or. peeling insulation were corrected using a vendor recommended and' licensee approved repair procedur During review of this activity, the inspector noted several positive aspects of licensee performance. The initial decision to expand the inspection scope to all major 4KV busworks was appropriate.~ However, expanding the scope just prior to or after the commencement of the outage posed several scheduling and coordination problems for the licensee. These issues received careful consideration and prompt licensee action. Plant operations review committee (PORC) involve-ment in this activity was noteworth Inspections were performed expeditiously and in a very well-controlled manne Consequently, electrical system and equipment out-of-service periods were held to. a minimum. Infrequently'used electrical system lineups were necessary to perform the' inspections. These were well planned, analyzed and executed by operations department personnel. Overall, performance during this activity demonstrated flexibility, teamwork and profess-ionalism in the licensee organization. The inspector had no further questions in this are .5 Feedwater Check Valve Flaw During performance of scheduled in-service testing (IST), the licen-see opened feedwater check valve FDW-28B for verification of freedom of internal piston movement. While the valve was open, a visual exam-ination of the inside surfaces of the valve was performed as required by ASME Section XI. Visual cracking was observed in the stellite wear pads in the piston guide porticn of the valv The cracking was located within the approximately one-inch wide stellite wear pad Wear pads provide a sliding surface for piston movement. The wear !

pads were created by machining a shallow groove in the bore of the piston housing and weld depositing stellite alloy. The bore was then machined to provide a cylindrical bore for the piston.

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' The licensee performed ultrasonic inspection of the valve to charac-terize the visually observed cracking. Two flaws were identified, one with a maximum flaw depth of .65 inch and the other was a 0.40 inch deep flaw on the other side of the valve. The deeper flaw was radiographer, confirming the fact that the flaw was contained entirely within the width of the stellite pad. The ultrasonic examiners reported that casting inclusions made it difficult to discern the crack tip from the inclusions (i.e., the flaw could be shallower than reported). The casting inclusions were also seen in the radiograph. Since the reported flaw depths were in excess of Section XI acceptance criteria, detailed flaw evaluations were required. The valve body thickness in the area of the flaws is approximately 2 to 2.1 inches. The licensee performed examinations of the other similar feedwater check valves. Although slight indica-tions were identified, all were contained within the width of stellite wear pads and none exceeded the pad thickness (approximately 90 mils).

The licensee performed detailed engineering evaluations and provided the results to the NRC:NRR in letter BVY 89-31 dated March 28, 198 In summary, the licensee concluded that the indications are stable, static flaws in the stellite wear pads resulting from cracking coinci-dent with casting defects. Based on conservative analyses and compar-isons with industry acceptance criteria, the licensee determined that the flaws were acceptable for service without repair for the next cycle of operations. By letter dated April 5,1989, NRC:NRR informed the licensee that, based upon an initial review of the licensee analy-ses, restart and plant operation was acceptabl In the March 28, 1989 submittal the licensee committed to repair or replacement of FDW-28B during the next refueling outage and instal-lation of an interim valve body leakage monitoring system. The insp-ector verfied installation and operability of the detection system prior to plant startup. This system will provide constant leakage monitoring during the operating cycle. The system consists of three moisture sensitive tape (MST) transducers mounted on the mirror insul-ation below the valve. The transducers have the ability to detect leakage as low as 0.1 gpm. The transducers provide a signal to an indicator / control unit mounted in the Reactor Building. The control unit interrogates all sensors once per second and provides a digital display of sensor location (s) for alarm or trouble conditions. The unit also provides remote alarm indication in the main control roo The detection system will be used by operations personnel to initiate further administration action / controls. These administrative con-trols identify operator action upon receipt of an alarm on the MST unit and compensatory action if the unit experiences trouble. Addi-tionally, the licensee implemented more restrictive criteria for allowable unidentified leakage in the drywell. These administrative controls were issued and implemented as operations standing orders.

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i The inspector found that the licensee approach to resolution of this issue was dynamic and well-organized. ' Engineering evaluations and-analyses appeared to be consistently l applied in a conservative manner. The inspector had no further questions in this are . Engineering-Support 8.1 Outage Modification ,

l In addition to corrective and preventive maintenance, numerous facil- l ity modifications were implemented during the outage. Various aspects i

'of;these activities, including the modification package, installation 1 and closecut, were reviewed. Control of the modification process-and ,

post-implementation testing were also observed. Following is a summ- '

ary of design changes, some of which were implemented prior to outage l commencemen Engineering Design Changes (EDCRs)

EDCR 86-407 - CRP 9-2 Modifications This design change performed modifications to resolve human engineer-ing deficiencies (HEDs) as a result of the detailed control room 1 design review (CRDR). It resulted in the relocation and/or removal of equipment. Operation of all relocated equipment remained the ,

sam Recorders RR-16-19-1A/B were remove The main. condenser .)

vacuum pump control switch and lights were relocated from CRP 9-6 to l CRP 9- Control switches.and associated lights for steam jet air ejector (SJAE) air valves FCV-11/12 were' removed. The OG-PCV-516A/B valve reset push buttons, located on the CRP 9-6 located below the filter indicators were removed. The offgas recorder selector switch was relocated from CRP 9-6 bench board section to the vertical ,

section. The FCV-102-35 indicator lights were relocated from CRP 9-6 *

bench board section to CRP 9-2 beside the FCV-102-35 controlle ECCR 86-408 - Modifications to CRPs 9-3 through 9-8 This design change also performed modifications to resolve HEDs as a result of the CRDR. It relocated the 345 kv digital voltmeter from CRP 9-8 to 9-7. The Rosemount vessel level and pressure indicator 1

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and recorder inputs were rearranged on CRP 9-5. The two major annun-icator controls (NSSS and BOP) were split and relocated into four ,

zones (CRP 9-8, 9-7 cnd 9-6, 9-5 and 9-4, and 9-3). !

EDCR 86-411 - Modifications to Main Control Board j l

This design change improved.the man-machine interface as denoted in i the CRDR. Lines of demarcation were added to the main control panels I to provide visual separation and reduce the cluttered appearanc All existing mimic lines were replaced to comply with a new color standard. About 215 switch handles were replaced. All labels were o

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made consistent in size, lettering, nomenclature, acronyms and abbreviations. Thirteen switch escutcheon plates were replaced to improve the correlation between the switch position and the control function. Holes left in the control room panels were sealed. All control room panels were painte EDCR 86-415 - Emergency Response Facility Information System (ERFIS)

NUREG-0737 requires the installation of a safety parameter display system (SPDS) to aid operators in rapid detection of abnormal condi-tions. The functions of ERFIS include SPDS and emergency operating procedure (EOP) support displays. Work was performed in the computer and user rooms, the main control room (MCR), the technical support !

center (TSC), the cable spreading room and the relay house. Details of the ERFIS modifications were also addressed in IR 89-0 ECDR 87-403 - Reactor Vessel Level Reference Leg Temperature Monitoring Upgrade The reactor water level monitoring system (RWLMS) uses the reference leg temperature for calibration purposes. During extreme transients the reference legs could approach saturation conditions. Reliable reference leg temperature are important to the control room operator for verification of accurate reactor water leve Type "T" thermocouple were installed on the reactor water reference legs in the drywell. They are accurate to within 10 degrees Although the modification was to non-nuclear safety electrical compon- !

ents they were programmatically treated as safety class and installed !

as a environmentally qualified (EQ) system. Existing sensors and cables were removed and replace EDCR 87-409 - High Speed Valve Actuator Modifications This design change modified certain high speed motor operated valves to reduce excessive seating thrust and added a mechanism to absorb overthrust. This reduces chronic valve damage and improves reliabi-lit Implementation was performed according to a priority lis Not all valves were modified this outage. The licensee expects to take up to two additional outages to complete this modificatio EDCR 87-412 - Diesel Fire Pump Injection Path One of the improvements suggested in the VY Containment Safety Study was to use the diesel fire pump to provide coolant (river water) to the drywell, torus or vessel (spray or injection) during station blackout conditions. In order to reposition certain AC motor opera-tors, power will be supplied by the John Deere diesel generator (JDDG).

The ability to use the JDDG to recharge the station batteries was also provided. A cable was run between the new distribution panel, ;

AC-DP-DIA, located in UPS-2A room, and Bus 9, compartment 6 l

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EDCR 87-413 - APRM/LPRM Power Supply Modification Regulatory Guide 1.97 requires the abilit'y to verify a successful plant scram following a LOCA. Local power range monitors (LPRMs) are qualified for ten minutes post-LOCA. However, the average power range monitors (APRMs) are powered by the reactor protection system (RPS)

motor generator (M/G) sets. During a loss of normal power, the'RPS M/G sets trip removing the APRMs and LPRMs. The LPRMs are needed to perform a post-accident monitoring function. Power transfer contac-tors were installed in the APRM power feed circuits. Vital AC and Instrument AC were used as the alternate power sourc New equipment was installed in the cable vault and the main control roo EDCR 88-401 - HPCI Low Pressure Pump Impeller Replacement High vibration readings have been seen on the HPCI pump train during normal monthly surveillance. A licensee decision was made to elimi-nate the vibration by replacing pump impellers. The booster pump impeller was changed from a 22" diameter four-vane (nonstaged) impell-er to a 22.5" diameter five-vaned (staged) impeller. This will re-duce the required net positive suction head (NPSH) which should im-prove performance. The entire rotating assembly was change EDCR 88-402 - Motor Operated Valve Wiring Modifications Motor-operated valves can be damaged from excessive backseating due to thrusting into the backseat under torqu verstress of the valve stem can occur at the end of the open cycl This design change made a wiring change and adjustment of limit switch settings to alleviate the proble For valves with four-rotor limit switches, a wiring change to the internal wiring of the limit switch contacts was made. Those valves with two-rotor limit switch contacts required an internal wiring change plus replacement with a four-rotor switc EDCR 88-403 - Feedwater Heater Repair and Modifications Inspection and repairs on the low pressure feedwater heaters began during the mini outage in June 1988. The temporary repairs were inspected and permanent mods were made. Steam inlet nozzles on the

3 heaters were replace Plant Design Changes (PDCRs)

PDCR 82-15 - MSIV Actuator Upgrade Actuators on the "A" and "B" outboard MSIV were changed as the last part of a continuing program to replace all actuator This change was prompted by parts obsolescence and to incorporate upgrades made by the manufacturer. All inboards and the "C" and "D" outboards have previously been complete _ _ _ _ - _ _ - _ _ _ _

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PDCR 86-05 - Switch Relocation

This design change performs modifications to resolve HEDs identified in the CRDR. Condenser vacuum isolation bypass switches on CRP 9-15/9-17_were switched with the RPS test switches. Circulating water booster pump' bypass gate control swithces on CRP. 9-6 and the condenser flood valve control switches on CRP 9-23 were rewire Keylock switch directions were revised on'RHRSW Pump A/C & B/C manual override switches on.CRP 9-3 and core spray syste:n 1/2 drywell

pressure test switches on CRP 9-3. This made all' switches which perform a similar function consistent in direction of operation and eliminated the RHR head spray valve control switches and ir.dicator on CRP 9- PDCR 86-06 - Alarms, Lights and Indicators This design change resolves HEDs identified in the CRC Indicating lights were aligned to facilitate comparative readings for specific radiation monitors on CRP 9-10, 1 Lights were revised to read,.

t- left to right, DOWNSCALE (white), UPSCALE or HIGH VOLT ON (amber) and UPSCALE HIGH-HIGH (red). Indicating lights were aligned to facili-

' tate comparative readings for the outdoor page silence switch, the station air compressor cooling water transfer switch, and the iodine filter switch located on CRP 9-2 PDCR 86-07 - Alarms and Indicators This design change resolves HEDs ' identified in the CRD Eight indi-cator lamps are used to monitor the scram bus status of the four banks of scram pilot solenoids. They are located on CRP 9-15/17. A R duplicate set of lamps was added to CRP 9-5 below annunciator A-7. A white indicator lamp was added to CRP 9-3 above.the HPCI initiation signal reset pushbutton to indicate all HPCI trips are reset and the system is available for auto initiation. Meters for the two diesel generators were added to CRP 9-8 to augment the local VAR meter <

A white light was added to CRP 9-7 to indicate a normal (deenergized)

state of the turbine vacuum trip switch (MTS-2) circui '

PDCR 88-01 - Reactor Building Load Shed Relays This PDCR implemented changes to the load shedding relays for MCC 8B and 98 because of harsh environment concerns. Some HFA relays were removed and replaced with Weidmuller terminal blocks. Operational i requirements of the load shedding system did not chang PDCR 88-02 - Secondary Containment Control This modification implemented hardware changes required for proper execution of E0P OE 3105, " Secondary Containment Control". Eight l reactor building area temperature monitors were added. Thermocouple l were installed in four 252' elevation areas, three 280' areas and one '

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'303F area. All indications were-terminated at the Chromalox panel on CRP 9-2 Lines were painted in the torus area and four corner room to indicate " MAX NORM OPER LEVEL" (green and 1" above floor) and " MAX-SAFE OPER LEVEL" (red and 12" above floor). All containment pressure instruments in the main control room ~ were rascaled from psia to psi PDCR 88-03 - Recirculation Pump Motor Snubber Removal Four 100 kip SS-4 snubbers installed on the recirculation pump motors-during the pipe replacment. outage were removed. . The as-built pipe stress analysis was found to be acceptable without these snubber '

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PDCR 88-05 - Drywell~ Pressure Alarm

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-Due to maintenance problems with pressure switch (PS) 5-16 being obsolete. and no adequate replacement available, the "Drywell Hi/ Low" pressure' alarm on CRP 9-5 was modified. This alarm is used to alert operators to changes in the drywell and provides no safety functio Plant Alterations (PARS)

PAR 88-009 - Turbine Rotor Replacement The main t'rbine u "A" low pressure rotor was replaced with a new monoblock design. This change was necessary. as a result of IGSCC on the wheel. The new rotor is-forged as a single unit eliminating the source of crackin Findings In general, the design change process for this outage was well- '

controlled. Design changes were' generally. developed with sufficient lead-time prior to outage commencement to allow comprehensive review Modification packages contained sufficient information to allow de-tailed analytical and safety reviews of the proposed change. Early review and approval of design changes eased the burden on engineer-ing, maintenance and operations organizations allowing coordinated planning and deliberate implementation. Confirmation of design change package quality was provided by the relatively low number of minor changes and engineering change notices (ECNs) required to effec-tively implement the modifications. The inspector identified no defi-ciencies in the design, implementation and testing of plant modifica-tion . Licensee' Event Reporting (LER)

The inspector reviewed the licensee event reports (LERs) listed below to determine that with respect to the general aspects of the events: (1) the report was submitted in a timely manner; (2) description of the events was accurate; (3) root cause analysis was performed; (4) safety implications were considered; and (5) corrective actions implemented or planned were sufficient to preclude recurrence of a similar even _ _ _ - _ _ _ - _ _ _ _ _ _ _-______-

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' The. LER 89-03, " Inadvertent Primary Containment Isolation System-(PCIS) Actuations Due to Spurious Spikes on the Reactor Building Vent-11ation Radiation Monitor", addressed two related spurious PCIS Group III actuations. The actuations are more fully described in Section 6.4 of this repor This was a well written and timely LER. Descrip-tions of the event, analysis and corrective actions were comprehen-sive. The LER fulfilled the above criteria and no deficiencies were identifie .2 MR89-04 l The LER 89-04, " Snubber MS-35 Fluid Loss and Function Failure Due to Worn Rod Bushing", described the visual and functional failure of shock suppressor MS-35 during TS 4.6.I.1 surveillance testing. Th LER provided good documentation of the event. Details of the snubber failure are presented in Section 7.1 of this report. The LER ful-filled the above criteria ~and no deficiencies were identifie .3 LER 89-05 LThe LER 89-05, " Inadvertent Primary Containment Isolation System l Actuation Due to an Inadequate Procedure", detailed a PCIS Group III actuation when the reactor steam dryer assembly was-removed from the reactor vessel. This actuation is more fully described in Section . The LER was well-written, timely and fulfilled the above cri- !

teria. No deficiencies were identifie '

9.4 LER 89-07-

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The LER 89-07, "1989 Appendix J Type B and C Failure Due to Seat Leak- '

age", addresses the results of containment penetration and valve test-in This testing is more fully described in Section 7.2 of this report. The LER provides a detailed description of test failures and conclusions. Further licensee analysis, details of corrective actions ,

and maintenance results will be provided in the PCILRT report approxi- !

mately 90 days after outage completion. The inspector noted an error in the LER assertion that no similar event concerning valve CA-89C had been reported in the last five year Valve CA-89A failed leak-age testing in 1984 and was reported to the NRC in LER 84-11 Revision 1 on August 16, 1984. The licensee will correct this error in the ,

PCILRT report. With the exception of this error, the LER fulfilled '

the above criteria, j i

9.5 LER 89-08 j The LER 89-08, "' Group Three Isolation as a Result of an Incomplete i Lifted Lead and Jumper Request Due to Personnel Error", addresses an unplanned PCIS Group III actuation and subsequent SBGTS initiation ,

caused by an inadequate lifted lead and jumper (LL & J) request. The

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details of this event are more fully described in Section 6.4 of thi report. The LER fulfilled'the above criteria and no deficiencies were identifie .6 LER 89-10 The LER 89-10, " Missed Diesel Fuel Oil Sample Due to Inadequate

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Administrative Controls", reports a missed monthly analysis of the E diesel fuel oil storage tan Details of this event are provided in Section 6.5 of this report. The LER fulfilled the above criteri The inspector noted that licensee corrective actions for a previous NRC identified unresolved item (88-08-01) should have prevented this even Lack of fully effective corrective action was not addressed in the LER event analysis or corrective action sections. This point was discussed with the licensee. The inspector was satisfied that the issue had received appropriate licensee attention. The inspector had no further questions in this are .7 LER 89-11 The LER 89-11, " Inadvertent Primary Containment Isolation System Actu-ation Due to Personnel Error When Moving Exposed Local Power Range Monitor", describes a PCIS Group III isolation due to a refueling floor radiation monitor actuation. Actuation resulted from increased radiation levels on the refuel floor when the " hot end" of a local power range monitor (LPRM) being transported to the spent fuel pool was brought too near the water surface (see Section 6.4 for details).

The LER was well-written and provides a good analysis of the even Planned corrective actions appear comprehensive. The LER fulfilled the above criteria and no deficiencies were identifie .8 .LER 89-12 The LER 89-12, " Defeat of One Hour Fire Barrier by Defective Door Latches", detailed a carbon dioxide (CO2) initiation in the west switchgear room which eventually caused a toxic gas system actuatio Details of this event are presented in Section 6.6 of this repor The LER provided a good analysis of the event and effectively identi-fied several contributing causes. Corrective actions appeared to be comprehensive. The LER fulfilled the above criteria and the inspec-tor identified no deficiencie .9 LER 89-13 The LER 89-13, " Reactor Vessel Inventory Decrease Due to Personnel 1 Error", reported an inadvertent decrease in reactor vessel water inventory while performing maintenance on the "A" RHR loop. This was a well written LER which provided good documentation and analysis of the event. Details of the event are presented in Section 6.7 of this report. The LER fulfilled the above criteria and no deficiencies were note . _ _ _ _ _ _ _ _ _ _ _ - - _ _ _

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9.10 LER 89-15'

The LER 89-15, " Spurious Relay Actuation Caused ECCS Initiation Signal Due to Lack of Procedure for Re-energizing Local Instrument Cabinet", reports an inadvertent partial actuation of ECCS equipment upon repowering the "B" ECCS Analog Trip Cabinet. The details of- .

this event'are presented in Section 6.8 of this report. The LER adequately described the event, causal analysis and corrective action. No deficiencies were identifie . Review of Licensee Response to NRC Initiatives 10.1 Storage Battery Audit (RTI 87-07)

Region I Temporary Instruction (RTI) 87-07, Storage Battery Audit, was' performed to assess the licensee program to assure that station wet cell storage batteries will remain operable in accordance with the current. licensing basis. The audit included review of the licen-see response to RTI 87-07, Attachment 2; surveillance procedures and'

documentation; system walkdowns; and, discussions with licensee mai -

tenance and engineering personne System Description Direct current requirements at the plant-are met by the 125 vde main station and alternate shutdown (AS-2) batteries, the 24 vdc emergency core cnoling. system (ECCS) batteries, and.the 430 vdc UPS batterie The main station batteries are located in a dedicated room and separ-ated by an eight-inch thick concrete block wal The AS-2 battery is located in 1A diesel generator room. These lead calcium batteries are supplied via static chargers from the 480 vac emergency buses. A spare charger is available if require The ECCS batteries supply-the emergency core cooling analog trip and automatic recirculation pump trip systems Two separate and independent 24 vdc lead calcium batteries are charged from 480 vac emergency buses. Alternating current ECCS loads may be supplied as required from two 430 vde UPS batteries via their respective charger / inverter Licensee Commitments The licensee is not committed to comply with any edition of IEEE Standard 450, Recommended Practice for Maintenance, Testing, and Rep 1-acement of Large Lead Storage Batteries for Generating Stations and Substations, or any other battery-related IEEE Standar IEEE 450-1975 is endorsed by NRC Regulatory Guide 1.129, Revision 1, Main-tenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants, and specified in NRC Inspection and Enforcement Manual, Part 9900 - Technical Guidance. However, licensee engineer-ing is guided by Standard 450 and station maintenance and surveill-ance procedures reference the standar . _ _ _ - _ - _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ -

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Battery Sizing The inspector reviewed the licensee d-c loading profiles and bases for station safety-related batteries. Calculation VYC-298 was revised on January 11, 1988 to derate the main station battery capacities to reflect a new mimimum average cell temperature. However, overall spare' capacity increased due to revision to reflect actual motor-operated valve inrush currents recorded during MOVATS testing vice original motor nameplate data. Calculation VY-EDCR-79-2-C1, dated July 1, 1980, demonstrates the spare capacity of the RPT/ Analog Trip System (ECCS) batteries. Since no service test is performed on the ECCS batteries, no load profile has been developed. These calcula-tions employ the conservative sizing method specified by IEEE Standard 485, Recommended Practices for Sizing Large Lead Storage Batteries for Generating Stations and Substations. Periodic testing has confirmed the ability of the batteries to supply emergency loads for the required duty cycles. Design changes are programmatically reviewed for impact on battery load profiles and spare capacitie Seismic Qualification The main station, UPS, ECCS and AS-2 batteries are qualified in accord-ance with IEEE Standard 344-1975, Recommended Practices for Seismic Qualification of Class IE Equipment for Nuclear Power Generating Sta-tions. The inspector verified that licensee periodic inspection pro-cedures were adequate tc maintain battery seismic qualificatio During walkdown of the main station batteries, the inspector noted that the two-tier racks were anchored either to the floor and wall or from the floor to ceiling. C&D technical manual 12-800, Station Battery Installation and Operating Instructions, specifies that racks be mounted to either the floor or the wal IEEE Standard 484-1987, Recommended Practices for Installation and Design of Large Lead Stor-

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age Batteries for Generating Stations and Substations, cautions l against stress created by conflicting modes of vibration when racks

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are mounted to both the floor and wall. ANSI /IEEE Standard 535-1986, Qualification of Class 1E Lead Storage Batteries for Nuclear Power Generating Stations, states that the information required for seismic qualification of the battery or rack (or both) shall include the installation requirements, including mounting method. Racks are to be fastened to the seismic test table in accordance with vendor in-structions and simulate actual installed conditions. Review of the main station battery seismic qualification reports revealed that the racks and batteries were not mounted on the test tables in the as-built configuration. The existing configuration has not been review-ed for acceptability against applicable seismic qualification utility group (SQUG) program criteria and NRC ground motion versus bounding spectra limit However, the licensee previously identified the dis-crepancy and plans to review this item to demonstrate that the equip-ment is seismically acceptabl _____--_-____ _ _ _ _ _ _ _

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Battery Rooms / Ventilation i

The main station batteries are located in a dedicated room within the cable vault. The inspector toured the room to examine general house-keeping, battery and rack condition, and ventilation system operabil-it Two folding metal chairs and a roller-mounted stool were found stored unsecured in the room. Test cables are stored on loosely mounted hooks on the east wall of the room. Electrical conduit to a junction box was not firmly fastened to the east wal The presence of the chairs in the battery room following post-test cleanup indicates that housekeeping controls were less than adequate in this are Main battery room ventilation is alarmed in the main control roo Technical specifications (TS) and procedures are adequate to ensure that hazardous hydrogen concentrations in the room are precluded if normal ventilation is lost. Finally, protection against such hazards is demonstrated by battery gassing calculations. The cable vault is posted as a fire control area and both fire and work permits are re-quired to perform maintenance in the battery areas. Fire brigade pro-cedures clearly indicate the dangers peculiar to large wet cell battery space The UPS and ECCS batteries are located in cages in the recctor build-ing. Ventilation is supplied by the building HVAC system. The AS-2 battery in the 1A diesel generator room has a low gassing factor Ond calculations show that on an equalizing charge weeks would be required to generate a 2 percent hydrogen concentration in this roo The inspector noted that during load testing of this battery, the diesel room door is blocked open requiring deluge system abort and periodic inspection by a fire watch. These battery areas were clean and free of debris and ignition hazard Electrolyte Temperature Control Electrolyte temperatures of all cells within a battery are measured quarterly in accordance with station maintenance and survetilance procedure OP 4210. A cell temperature correction factor is then app-lied to measured specific gravity to standardize the results to a nom-inal 77 degrees F. The inspector reviewed representative data sheets for all station safety-related batteries to verify that electrolyte temperatures met battery system design bases, vendor technical manual and IEEE Standard recommendation The C&D Power Systems manual 12-800, applicable to the main station batteries, states that variation in temperature of more than five degrees F will cause the cells to become unbalance Exide Instruc-tions for Installing and Operating Stationary Batteries, section 58.00, applicable to the UPS batteries, states that cell temperature should be approximately the same, and that non-uniformities in float voltages and specific gravities may occur as a result of uneven cell

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temperature IEEE Standard 484-1987 includes in its design criteria that battery location or arrangement should result in no greater than a five degree F temperature differential between cells at a given -

tim Licensee records indicate that the five degree F temperature differ-ential has been exceeded on the UPS "A" and main station "B" batter-ies. Current procedures do not identify allowable temperature ranges or differentials in acceptance criteri Resolution of this item is unresolved pending licensee review to determine the acceptability of this condition and its impact on expected battery and individual cell capacity and life (50-271/88-02-02).

Charging and Maintenance Practices All safety-related batteries are maintained on a float charge in acc-ordance with vendor instructions. Equalizing charges are not per-formed at specific intervals or based on average cell specific grav-ity readings as recommended by IEEE Standard 45 However, specific gravity and cell voltages on pilot cells are recorded weekly and data from all battery cells are recorded quarterly. The licensee trends this information and performs equalizing charges accordingly. This practice conforms to the requirements of applicable vendor technical manuals. The criteria for battery water quality and addition are t adequately addressed in station procedures. Pilot cells are rotated periodically. Hydrometers are checked for calibration annuall The licensee typically leaves thermometers installed in the sample tubes of pilot and other cells. The licensee indicated to the inspec-tor that discussions with battery vendors (C&D and Exide) revealed that no adverse impact on cell operability would result in the event that an alcohol thermometer were to break in the cell. Nonetheless, the Exide technical manual addresses installation of thermometers in cell flame arrestors only and explicitly states that thermometers are not to be left in cells in seismic shock area In response to the inspector's concern regarding this practice, the licensee agreed to l resolve this apparent conflict.

I As a result of a records review and system walkdown, the inspector made the following observations to the licensee:

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On March 7, 1989 the quarterly surveillance of ECCS batteries A ,

and B was performed incorrectly by contractor personnel in that j the required specific gravity level corrections were not mad Operating Procedure OP 4210, Rev. 14, dated June 6, 1988, con- I tains step-by-step instructions for specific gravity correc-tion Prerequisite 5.4 of the procedure requires that it be reviewed with all personnel assigned to its performance to ,

ensure that all aspects of the procedure are understood. A I signoff by the maintenance supervisor is included on data sheet

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4210.01 to confirm the performance of the prerequisite. As a l

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result of interviews with the author of the procedure and the -

supervisor involved, the inspector concluded that the intent of I the prerequisite was not clearly understood by maintenance per-sonnel. The intent of this prerequisite is that maintenance supervision briefs the performing personnel prior to commence-ment of the procedure. This action was not accomplished. Addi-tionally, review of the data by licensee supervision and manage-ment' failed to identify the discrepancy. The inspector deter-mined that the scope of the review was-inadequate to reveal the-

~ discrepancy in'that data was reviewed only for conformance of final gravities and voltages to TS requirements and not trended against prior dat A surveillance performed on the "A" UPS battery on October 17, 1988 documented.a battery terminal voltage of 432 vdc but a high charger output voltage of 463 vdc. This discrepancy is no identified by a comment on.the data sheet Surveillance performed on December 27, 1988 and February 21, 1989 on the "B" main station and "A" UPS batteries respectively, indicated temperature differentials among cells of greater than 5 degrees F, yet no comments are recorded regarding these-difference In February 1989 cell 52 of main station battery "A" was replaced under maintenance request (MR)88-196 However, the inspector's review of the completed work document revealed'that:

(1) form VYAPF 0200,03, Equipment Failure / Probable Cause Records, recorded the cell replaced as being in main-station battery "B"; and (2) the EQ Information and Data Sheet likewise referenced main station battery "B".

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During walkdown of the ECCS batteries, the inspector noted that nineteen sample tube caps were badly cracked and two caps were missing. As a result of the inspector's comments the caps were immediately replace While the discrepancies noted above are not necessarily indicative of programmatic failures, a lack of attention to detail in performing, recording and reviewing battery maintenance is evident and warrants management attentio Performance and Service Testing The inspector reviewed battery performance and service test documen-tation for adherence to TS periodicity requirement Performance test current and service test load profiles, where applicable, were verified to meet the requirements of IEEE Standard 450-1980 and l 485-197 I i

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A service test is performed to verify the ability of a battery to 'l satisfy the design requirements (duty cycle) of the de system. A performance test is a constant current discharge designed to detect any change in the capacity of a battery as determined by the accep- ]

tance test. As a result of procedure review, the inspector made the )

following observations: ,

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Performance tests on main station, UPS, and ECCS batteries are not performed "as found" (i.e. reflective'of current maintenance practices) as recommended by IEEE Standard 450 in that (1) an equalizing charge is performed prior to the test, and (2) cell connections are checked clean, tight, and free of corrosion prior to discharge. However, the inspector noted that the station procedures follow the recommendations outlined in the respective vendor technical manual Current procedures do not require annual discharge testing of batteries which show signs of degradation or have reached 85% of

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expected service life. The licensee reviews the results of performance tests for trends indicative of significant decline in capacity. Main station batteries are given a performance test every refueling cycle to meet TS requirements. Since the licensee conservatively replaces batteries rather than continue into another operating cycle with degraded cells or batteries, current practice is considered acceptable by the inspecto The inspector noted that the licensee has developed new proce-dures for and performed service tests of the main station batteries. A new performance test procedure has been developed for the AS-2 battery, but has not yet been performe Conclusion The inspector found the licensee program for maintaining safety-related battery systems to be generally adequate. However, inade-quate data review by licensee supervision resulted in failure to detect the incorrect calculation of corrected specific gravities for the ECCS batteries. Failure to document minor housekeeping, material and operational discrepancies on battery surveillance data forms may re.flect a lack of attention to detail regarding system conditions.

l Licensee evaluation and followup of battery thermometer installation and cell electrolyte differential temperature issues are require . Review of Periodic and Special Reports Upon receipt, the inspector reviewed periodic and special reports submit-ted pursuant to Technical Specifications. This review verified, as applicable: (1) that the reported information was valid and included the l

NRC required data; (2) that test results and supporting information were I consistent with design predictions and performance specification; and (3)

that planned corrective actions were adequate for resolution of the

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I problem. The inspector also ascertained whether any reported information 1 should be classified as an abnormal occurrence. The following reports l were reviewed:

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Monthly Statistical Report for plant operations for the month of February 198 Special Report submitted in accordance with TS 6.5.F. This TS requires periodic leak testing of sealed radioactive sources and requires submittal of a special report to the NRC if greater than 0.005 microcuries (uC1) of removable containmation is found. During the semi-annual radioactive source leak test, a Uranium slab source,

.used to verify beta response of Eberline R0-2 dose rate instruments, was found to have 0.017 uCi of removable contamination. The source 4 had successfully passed its last routine leak test. The source has l been in use for many years and the adhesive that holds the mylar covering had begun to break down allowing contamination to escape. A comprehensive smear survey was performed of the areas where the source is used and stored. No additional contamination was foun The source was removed from service, deconned and re-sealed with a new protective covering. The source successfully passed a leak test and was returned to servic Semiannual Effluent and Waste Disposal Report for Third and Fourth Quarters of 198 . Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the findings. A summary of findings l for the report period was also discussed at the conclusion of the inspec-tion and prior to report issuanc No proprietary information was identi-fied as being included in the report.

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ATTACHMENT A I

KEY OPERATIONAL ACTIVITIES DATE TIME ACTIVITY 02/10 1207 Drywell/ Torus OP <1.7 psid. Commenced de-inerting in preparation for reactor shutdown and drywell entr Commenced reducing reactor powe Core flow at 50%; commenced inserting rods; power (PWR) level at 53%.

1853 Recirculation flow at minimum spee Swapped house loads to SU transforme Reactor PWR 19% holding for LPRM/APRM overlap surveillanc Completed drywell entry and inspectio Reactor engineering (RE) completed LPRM-APRM overlap continuing with reactor shutdow Removed turbine from grid, 2252 Placed mode switch to startu Placed shut down iodine filter in servic /11 0106 All rods inserted, reactor shutdow Mode switch in refue Completed RCIC-22 operability tes Started reactor cool down via #1 turbine bypass valv Completed secondary containment capability check -

satisfactor Started shutdown cooling on "A" RHR loo Reactor coolant <212 degrees Shut MSIV's, venting thru reactor head vent _-. - _ - - - _ _ - _ _ _ _ _ -

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ATTACHMENT A 2 DATE TIME ACTIVITY l 02/12 0425 Raised reactor pressure to 24 psi for primary containment leak rate test (PCLRT).

1010 Raised reactor pressure to 44 psi for PCLR Drywell head remove Control rod friction testing complete and sati sf actor /13 0435 Received spurious reactor building ventilation channel "B" radiation high and Group III PCIS isolation; reset sam Reactor vessel head de-tensioning complete /14 0615 Reactor vessel head lifte Secured reactor building heating and ventilation for secondary containment capability check and particularly the outer railroad door seal Reactor building heating and ventilation returned to service. Secondary containment capability check satisfactory per OP 4116 on outer railroad passive seal alone and on inflatable sea Group III isolation on refuel floor radiation monitors due to steam dryer lif Commenced control rod drive changeout Vessel drained to steamlines to facilitate removal of steam separato Mode switch to shutdown in preparation to transfer core spray suction for reactor cavity flood and core spray acceptance tes Mode switch to refue ___-_- _ _- _ __ -

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ATTACHMENT A 3 DATE- TIME ACTIVITY ,

I 02/15 0005 Secured reactor cavity flood up and started establishing cavity water clarit Removed spent fuel pool (SFP) gate /16 0808 Completed refuel interlocks and daily checks I satisfactory for fuel moves in spent fuel poo Completed SFP fuel move All reactor cavity lights (4) installed and operabl Completed control rod drive changeouts ,

satisfactoril Placed mode switch to S/ .

02/17 0652 Backfeeding via main transforme Report of fire in area of cooling tower West cooling tower #1 fan alternate power cubicle breaker coil was found burned. Opened alternate power supply breaker in the diesel generator roo Reports from fire brigade stated there was no smoke or flame but there was an electrical burning odo Removal of source range monitor (SRM) shorting links to place SRMs in non-coincidenc Completed weekly refueling interlock Fire alarm in reactor buildin Fire brigade respondin Fire alarm determined to be caused by welding in HPCI roo Authorized commencement of fuel move _ --__ -- _ ______ -_a

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ATTACHMENT A 4 DATE TIME ACTIVITY 02/20 0330 Completed initial fuel shuff'le. Set up for control rod blade changeouts 1245 Started SFP fuel move Completed SFP fuel move Notified by NRC that red phone is out-of-service due to broken lines. Verified land lines operabl Notified by NRC that red phone is operable. Phone check satisfactor Reactor building fire panel alar Fire alarm in torus area. Workers using heat shrink gun in area set off detector in torus catwalk are /22 1907 Identified "B" RHR heat exchanger channel baffle cracks during inspectio /23 1220 Completed control rod blade changeout and started LPRM changeout Received Channel "A" West refuel floor high radiation alarm causing Group III isolation and SBGT initiation (both trains). Refuel floor west radiation monitor was reading 12 mr/hr and the high alarm light was energize Confirmed that Group III isolation had occurre Verified that high radiation condition was caused ,

by close proximity of an LPRM string to the surface of the fuel pool while traversing the cattle chut Continuing LPRM changeouts.

l 1625 The "C" ADS accumulator check valve failed to pass its operability test per OP 4028.

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ATTACHMENT A 5

'DATE TIME ACTIVITY 02/24 0530 Completed LPRM installation Commenced fuel move Fire alarm in turbine loading ba Secured from fire in turbine loading ba ;

Bypassed turbine loading bay fire syste Fire watch poste Commenced fuel bundle channel swap /25 0255 Completed channel swaps, commenced final fuel shuffle /27 1245 Reactor building ventilation secured for secondary containment capability chec Reactor building ventilation in service; secondary containment capability satisfactor Completed final fuel shuffle Commenced fuel seating verificatio /28 0200 Completed fuel seating verificatio Commenced core verificatio Commenced fuel bundle swap in reactor vesse Completed fuel bundle swap in reactor vesse Mode switch to S/V for rod worth minimizer (RWM)

surveillance per OP 4450.01.

l 1134 Mode switch to refuel, RWM surveillance satisfactory, declared operabl Commenced CRD friction testin /01 0025 Fire alarm in feed pump room. Welding in progres Halted friction testing to do additional core verification.

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l ATTACHMENT A 6 i

l DATE TIME ACTIVITY i

03/01 0750 Recommenced friction testin Transferred house loads to S/U transformer /02 0358 Mode switc! to startup for insequence critical testin Reactor critical. Sequence 13-A-2, Group 2, rod 26-31 at position 20, 55 second period at 8 degrees Shutdown reactor. Mode switch to shutdow l

)

0615 Transferred house loads to main transformer i through backfee Secured CRD system for CRD-115 check valve tes "A" diesel generator removed from service for l outage maintenanc /03 1355 Secured "B" RHR loop. Ground alarm on Bus ,

West switchgear alarm. CO2 discharge to west !

switchgea Toxic gas monitor (TGM) initiation. Operators donned self-contained breathing apparatu ;

1440 CO2 samples in control room satisfactor l 1532 Continuous fire watch stationed in the west (

switchgear room while system is discharge /04 1303 Received full scram while repowering the reactor protection system (RPS).

l 03/05 0120 Returned west switchgear room CO2 system to normal. Declared west switchgear room CO2 system j operable and secured firewatc ;

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ATTACHMENT A 7 DATE TIME ACTIVITY 03/05 0850 Started SBGT and secured reactor building ventilation for PCLR Started reactor building ventilation and secured SBG /06 0928 Deenargized RPS Bus "A".

1120 Draining reactor cavit Partial Group III isolation occurred during deenergization of "A" RPS. LL/J installed to prevent isolation was not sufficien /07 0105 Secured cavity draindown for shield block installatio Commenced cavity draindow Secured cavity draindow /08 0730 Commenced draining reactor cavit Secured draining cavit /09 0110 Service platform installed in preparation for invessel inspection Reactor engineering (RE) commenced invessel inspection Identified "A" RHR heat exchanger baffle crackin Started "A" CRD pump to make up 5 feet (approximately) of water to reactor which drained to torus via RHR-16A when maintenance personnel

' stroked RHR-15A & C to the 95% open limit. Shut RHR-69A & C to isolate RHR-16 _

c 7

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' ATTACHMENT A 8 DATE TIME ACTIVITY 03/10 0040 Declared Unusual Event terminated based upon AP 3125 indication of coolant loss from the primary coolant syste Refuel floor HP reported there was no dose rate increase during level decreas Maintenance completed work on RHR-15A & C valve Secured "A" CRD pump, reactor level at flang Resuming in-vessel inspection While reenergizing ECCS cabinets 25-5B & 25-6B an apparent surge in the electronics caused a low-low reactor water level signal which started "B" DG, UPS "A" trip, tripped RHR S No injection occurre Completed invessel inspections, all satisfactor Decreased reactor level one foot below reactor flange for maintenanc Returned RPS "A" to servic /12 1703 Commenced diesel generator "A" maintenance testin /13 0405 Unioaded and secured "A" diesel generato Started and loaded "A" giesel generator for one hour reliability demonstration ru Unloaded and secured "A" diesel generator following availability run "A" diesel generator available but not operabl /14 0805 Deenergized "B" RPS Bus for maintenance and modification EDCR 88-401, HPCI Low Pressure pump impeller I installation complete i j

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ATTACHMENT A 9 DATE TIME ACTIVITY 03/14 1450 Commenced reactor cavity fill to top of bottom shield bloc Started Standby liquid control (SLC) flow test to the reacto i

1915 Completed SLC testin '

03/15 0607 Chemistry reports "A" RHR heat exchanger (HX)

service water side sample unsatisfactory. Water was high in tritium and magnesium, cobalt and l zin Chemistry reports "A" RHR HX tritium sample positiv Chemist y department reports "A" RHR HX samples unsatisfactor RHR HX "B" sample satisfactor Shield blocks removed. Recommenced reactor cavity fill in preparation for separator installatio Completed reactor cavity fill.

03/16 1525 Identified FDW-288 stellite near-surface cracks in guide pad /18 1145 Commenced cavity draindow Started "B" diesel generator for eight (8) hour operability run.

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2235 Separator set down in reactor vesse ;

i 03/19 0505 Secured cavity drain (reactor level 4" below flange).

0507 Secured "B" diesel generator operability run satisfactor I

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ATTACHMENT A 10 DATE TIME ACTIVITY 03/20 0115 Started cavity drai Secured cavity drain down, reactor level 1 foot L below flange area.

l 2233 Started reactor vessel drain down to top of moisture separator for steam line plug remova /21 0238 Started and loaded "B" diesel generator to verify operability following maintenanc Secured reactor vessei drain down, reactor vessel level 6" below top of steam separato Secured "B" diesel generator, operability sati sf actor Bypassed East and West refuel floor radiation monitors in preparation for steam dryer lif Refuel radiation monitors back in servic Reactor building heating and ventilation systems back in servic Secured shutdown cooling to allow vessel heat u Maintenance reports vessel head in plac Started "B" RHR loop in S/D cooling mode. Inlet to RHR HX isolated to allow vessel heat up in preparation for head tensionin /22 0153 Started "A" CRD pump and placed CRD system in servic Verified vessel flange temperature >70 degrees Started reactor vessel head tensionin Secured "A" CRD pump (drives flushed per GE SIL 427).

1720 Reactor vessel head tensione Draining reactor vessel to normal leve _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _

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ATTACHMENT A 11 DATE TIME ACTIVITY 03/22 1915 Draining reactor cavity seal plate area to drywell sump Secured cavity drainin Restarted reactor building ventilation, secured SBG Secondary containment capability satisfactor Secured vessel draindow Reactor vessel head piping installe )

03/23 2000 Started "A" diesel generator for monthly surveillanc /24 0410 Secured "A" diesel generator following operability ru /25 1355 Started "A" CRD pum Performed ECCS integrated testing satisfactoril /27 1246 Placed mode switch in refue Shut head vent Commenced reactor vessel cold hydrostatic test. Vessel flange temperature 181 degrees Completed 85 pound hydrostatic leak check satisfactoril Reactor pressure at 503 pound Vessel pressure at hydrostatic pressure (1013-1023), inspected system for leakag /28 0021 Mode switch to S/U to perform S/D margin check in preparation for single rod scrams (OP 4424).

Mode switch to refuel, S/D margin check

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0030 satisfactor I

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' ATTACHMENT A 12

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DATE TIME ACTIVITY 03/28 0040 Commenced single rod scram testin RE reported completion of scram testin Commenced depressurizing reacto Notified NRC Operations Center pursuant to 10 CFR 50.72(b)(2)(i) of leak found on "D" main steam ,

line flow element during cold hydro at 975 pound I 1726 Mode switch to S/ Drywell head in place but not bolte /29 1750 Reactor vessel vented via manual vents in preparation for the type "A" primary containment integrated leak rate test (PCILRT).

1810 Commenced leak rate test (LRT) of drywell personnel acces Drywell personnel access LRT completed satisfactoril Pressurizing drywell for PCILR /30 0000 Received drywell high pressure alarm. Core spray pumps "A" and "B", RHR pumps "A" and "C" auto started. No injection to vessel took plac Pumps secured and placed in pull-to-loc Isolated drywell from external air compressor Commenced 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months stabilization period at 44 psi Pressurized drywell . Restarted stabilization perio Commenced PCILR Continuous fire watch establihsed in west switchgear roo Placed west switchgear room CO2 system to abort and declared inoperable due to unqualified firing head I

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ATTACHMENT A 13 DATE TIME 1 ACTIVITY 03/31 1150 Received report of train derailment in Brattleboro. Four cars off the tracks, one has a minor fuel oil leak. Leak is contained. No impact on plant operation pCILRT complete Commenced verification testin PCILRT testing complet Started "A" diesel generator for functioned test following AS-2 battery maintenance and maintenance for SW-43A. Test satisfactory and secure Commenced venting primary containmen /01 2210 Secured shutdown cooling in preparation for RHR alternate shutdown tes Started and loaded "B" diesel generator functional test following SW-43B/SW-319B maintenanc Unloaded and returned to normal standby statu /02 0040 Completed operability testing of "A" RHR loop after alternate shutdown testin Started and loaded "A" diesel generator in l preparation for stuck breaker testin Started and loaded "B" diesel generato Commenced stuck breaker testing in 345 yar Completed stuck breaker testing satisfactoril Secured "B" diesel generato Secured "A" diesel generator. Both diesels in standb /03 0955 Perturbated reactor vessel level.

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ATTACHMENT A 14 DATE TIME ACTIVITY

, 04/04 0230 Unioaded and secured "B" diesel generato Secured reactor building ventilation in preparation for secondary containment capability chec Secondary containment capability satisfactor Drywell access door strongbacks installed, interlocks restored and both doors shu Started "A" RHRSW pump to test RSW-89A and secured. Appeared RSW-89A did not ope Placed "A" RHRSW pump breaker in test to stroke RSW-89 Completed drywell personnel air lock LRT i satisfactoril /06 1345 Mode switch to refue /07 0530 Drywell personnel access LRT unsatisfactor Completed MSIV partial, functional, and fast )

closure surveillanc Seals replaced on drywell personnel hatch doors and strongbacks installe Mode switch to S/U for RWM surveillanc Commenced pulling rods for reactor startu Locally venting first rod drive per stuck rod procedur /08 0155 Reactor critical on CR 30-11, position 4, sequence 14AZ, Group 3 with 121 seccad period and reactor coolant temperature of 195 degrees Notified Chemistry of 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months sample requirement and requested vessel water 02 samples. Holding reactor coolant temperature between 200 degrees F and 212 degrees l

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ATTACHMENT A 15 l

DATE TIME ACTIVITY .

04/08 0420 0xygen <200 ppb, continued reactor heat-u Commenced RCIC testin Completed RCIC overspeed testin Completed SRV testin Commenced HPCI testing, would not overspee Completed HPCI overspeed testin RCIC recoupled and operabl Holding reactor pressure at 150 pound ;

2255 Reactor at hot hydrostatic pressure for inspectio /09 0340 Inspected drywell. No leaks detecte Mode switch in Ru Started RCIC for pump operabilit Secured RCI RCIC in alternate test mod RCIC alternate surveillance satisfactor Started RCI Secured RCIC, declared operabl Leak rate test of drywell access satisfactor Started HPCI for post-maintenance testin HPCI turbine tri Commenced inerting drywel Commenced rolling main turbin Started HPCI for post-maintenance testin Entered OE-3104 torus volume >70,000 f Secured HPCI.

l 1401 Phased generator to gri Torus volume <70,000 ft3. Transferred 8,700 gallons to radwaste. Exited OE-3104.

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ATTACHMENT A 16 .

I DATE TIME ACTIVITY 04/09 1455 Declared Unusual Event terminated due to torus water leve Started HPCI on full flow tes .25 Secured HPC Secured N 2 purge lineup, commenced establishing drywell/ torus D Declared HPCI operabl Increasing reactor power with control rod Holding reactor power at 22% CT Drywell to torus DP >1.7 psi /10 0047 Removed generator from grid for turbine testin Completed turbine overspeed testing satisfactoril Phased generator to the gri l l

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v t e Inspection Report - Vermont Yankee - 1989002
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \|
1989 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 14(0) 7(0) 8(0) 9(0) 11(0) 12(0) 13(0) 14(0) 15(0) 80(0) Security Operator Exams Emergency Planning Other

IR 05000271/1989002

Text

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