IR 05000029/1985024

Insp Rept 50-029/85-24 on 851126-860106.No Violation Noted. Deficiency Noted:Setpoint for Main Coolant Sys Low Set Code Safety Valve Exceeded Tech Spec Requirement

ML20141E305
Person / Time
Site:	Yankee Rowe
Issue date:	02/12/1986
From:	Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20141E296	List: IR 05000029/1985024 ML20141E288
References
50-029-85-24, 50-29-85-24, NUDOCS 8602250206
Download: ML20141E305 (17)

Text

.

.

U.S. NUCLEAR REGULATORY COMISSION Region I Report N /85-24 Docket N Licensee N OPR-3 Licensee: Yankee Atomic Electric Company 1671 Worcester Road Framingham, Massachusetts 01701 Facility Name: Yankee Nuclear Power Statio_n Inspection at: Rowe, Massachusetts Inspection Conducted: November 26, 1985 - January 6, 1986 Inspector: H. Eichenho en Resident Inspector

/' fd Approved By: '

T. Elsasser, W , Reactor Projects Section 3C f

'Date Inspection Summary: Inspection on November 26, 1985 - January 6, 1986 (Report No. 50-29/85-24)

Areas Inspected: Routine onsite regular and backshift inspection by the resident inspector (126 hours0.00146 days <br />0.035 hours <br />2.083333e-4 weeks <br />4.7943e-5 months <br />). Areas inspected included: Operational safety verification reviews, bi-monthly safety system walkdown, review of radiological controls, review of events requiring telephone notification to the NRC, review of plant events, maintenance observations, Plant Information Report reviews, cold weather prepara-tion, Licensee Event Report reviews and followup, surveillance observations, and Plant Operations Review Committee activitie Results: No violations were identified by the inspector; however, one deficiency, exceeding the TS-required setpoint for the Main Coolant System's low set code Safety valve, was classified as a licensee identified violation (Section 11).

Licensee development and use of detailed procedures to control routine activities (Section 3), and a positive trend of strong interdepartmental support for personnel compliance with established radiation protection practices were considered notable strengths. Several areas needing increased licensee attention were use of Special i Orders in lieu of procedures, operator attentiveness to off-normal indications, and qualitative assessment guidance for instrumentation checks (all Section 3).

? [

.

.

DETAILS

!

1. Persons Contacted Plant Operations B. Drawbridge, Assistant Plant Superintendent T. Henderson, Technical Director N. St. Laurent, Plant Superintendent The inspector also interviewed other licensee employees during the inspection, including members of the Operations, Radiation Protection, Chemistry, Instru-

ment and Control, Maintenance, Reactor Engineering, Security, Training, Tech-nical Services, and General Office Staff . Summary of Facility Activities d'

At the start of the inspection period on November 26, 1985 the plant was shutdown and activities associated with the Cycle XVII-XVIII refueling outage were in progress. Plant heatup commenced on December 2, 1985. On December 5, 1985, the licensee initiated Core X"III Pnysics Testing; initial criticality was achieved, with the testing being satisfactorily completed on December 7, !

1 1985. The plant remained in Mode 2 to facilitate contractor work on turbine related problems. A reactor scram from low power occurred on December 9, 1985 asaresultofacontractoremployeeinadvertentlybumpingarelaywhilecon-ducting post modification cleanup within the control room s Main Control Boar On December 10, 1985, the plant achieved Mode 1 operation and was phased on to the gri Due to a nitrogen leak in the No. 1 Station Service Transformer, :

the main generator was removed from the grid for a period of time on December l 11, 1985. The subsequent power escalation was halted on December 17, 1985 and l a load decrease from 73 to 65% power was effected, due to excessive leakage from the No. 1 Heater Drain Pump. Following repair of this pump and a load increase, the No. 3 turbine control valve stuck closed. Plant loading was brought up to 97% of full load on December 23, 1985 with the No. 3 control

valve in the shut position. A plant shutdown to Mode 2 was initiated on De-cember 28, 1985 from 97% power to allow repair of the No. 3 control valve.

i A reactor scram occurred while in Mode 2 (plant puwer at 2%) on December 28, 1985, due to a false High Start Up Rate. This false trip signal was induced while maintenance was being performed on the No. 3 Intermediate Range Channe On December 29, 1985, a failure of the No. 3 Boiler Feed Pump (BFP) and motor occurred while plant operators were preparing to return the plant to operation from Mode 2. Subsequently, the generator was phased on to the grid on December 30, 1985 and, while undergoing a reactor power increase, the main coolant !

chemistry results showed that the Dose Equivalent Iodine (DEI) level was 74% '

of the Technical Specification (TS) limit. A rapid reduction of the DEI level (less than 20% by 8:00 a.m. on December 30,1985) was observed. The No. 3 BFP was returned to service on January 4,1985, which allowed operators to in-

crease the plant's power output above 78%. At the end of the inspection period

.

.

the plant was at 99% power with a DEI level that was 5.2% of the TS limit, and decreasing. The licensee has initiated a detailed review of main coolant chemistry data to determine the reason for the DEI excursion during the power increas . Operational Safety Ver.fication Reviews Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCOs, instrumentation, recorder traces, protective systems, control rod positions, Containment tempera-ture and pressure, control room annunciators, radiation monitors, radi-ation monitoring, emergency power source operability, control room and shift supervisor logs, tagout logs, and operating orders. No inadequacies were identified except as noted belo A review of the Special Orders (50) Log resulted in the inspector recommending to the Fire Protection Coordinator and the Operations Department that the information contained in 50 No. 85-96 be incor-porated in an appropriate plant procedure. The information was is-sued to clarify confusion associated with tagging out and initiating the Carbon Dioxide Fire Protection System for Manhole No. 3. On December 6, 1985 the licensee initiated a procedure change to OP-2707, Operation of the Fire Suppression System Concern about the licensee's use of Special Orders in lieu of ap-proved procedures was previously identified in the SALP Report 50-29/85-99; the report indicated that this area requires evaluatio Management attention to ensure that this evaluation is conducted is warrante The inspector noted that increased shift activity has become neces-sary for recharging nitrogen bottles for the 100 psig nitrogen sup-ply system. This system is used in operating certain valve opera-tors in the Low Pressure Safety Injection (LPSI) Accumulator Syste The necessity to refill the storage bottles is due to leaking sole-noid operated valves SI-SOV-46 and -47. A plant shutdown to Mode 5 (cold shutdown) will be required to replace the valves. Safety related Maintenance Requests (MR) 85-1556 and -1557 were issued on December 14, 1985 to control the planned maintenance activity. The inspector verified that when Plant Operators recharge the nitrogen supply bottles they utilize Procedure OP-2656, Operation / Recharging the ECCS Accumulator Power Operated Valve Nitrogen Supply Bottle, to control the proces During the inspection period, the licensee issued a new procedure OP-2676, Operational Activities Associated with Routine LPSI Accum-ulator Alarms. The procedure documents operational activities asso-clated with realigning the Accumulator System and helps ensure con-tinued operability as required by the TS. The inspector views the

.

.

development, issuance, and use of this procedure as a positive lic-ensee action that will enhance control of selected safety related activitie The inspector had no further questions on this ite During a review of control room instruments on December 30, 1985, at approximately 4:30 p.m., the inspector noted that the LPSI Accum-ulator pressure indicator, SI-PI-5, was indicating a pressure sig-nificantly below 0 psig on its 0-800 psig scale. This was of par-ticular concern since TS operability of the accumulator is defined l as a nitrogen cover pressure of less than 15 psig. With a reading of less than 0 psig, actual pressure was impossible to determin Therefore, the inspector questioned the Shift Supervisor (SS) rela-tive to the accuracy of this indication with respect to meeting operability requirements. The SS directed the control room opera-tors to acquire the Accumulator pressure from a local calibrated gauge, listed the anomalous condit. ion on the shift turnover log, and generated HR 85-1681 to initiate corrective actions. Additional inspection showed that shortly before the inspector's observation, the control room SI-PI-5 indicator was read by an operator perform-ing his once per-shift checks. A value of 0 psig was entered on Rowe )

.

Station Log No. 2 for the Accumulator pressur TS surveillance requirement 4.5.1.a requires the licensee, in part, to verify the nitrogen cover pressure at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (actual checks are once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />). This is one of the checks that provide for ,

!

demonstration of continued operability of the LPSI Accumulato The inspector followed the licensee's corrective actions and re-viewed the results of OP-6464, Rev. 4, LPSI Accumulator Pressure Channel SI-P-5, conducted on December 31, 1985. The calibration data indicated that at 0 psig input pressure, the as-found indication was less than the 0 indication mark. The other test pressure inputs showed errors of between 10-15 psig less than input pressure. The acceptable limits are +/- 16 psig. The calibration procedure does require zero and span adjustments. Following the calibration, the data showed the instrumentation channel to be performing in a satisfactory manne ,

The inspector discussed with plant supervision his concern that the control room operators did not question a reading of less than 0 l i

psig, particularly since TS operability for the accumulators was defined as "less than 15 psig." Additional observations pertaining to an apparent lack of operator attentiveness to off normal control room indications are detailed belo During a control room tour on December 31, 1985, the inspector ob-served the recorder trace of the No. 4 Steam Generator (SG) Blowdown Monitor reading in an erratic fashion as compared to the recorder traces for the other SG monitors. Because TS Section 3/4.3.3 and l

l l

.

.

Table 3.3-4 require this monitor to be operable in Modes 1 thru 4, and the trace appeared not to be operable, the inspectcr questioned the Shift Supervisor (SS) and conducted a review of Operator obser-vations and actions pertaining to the performance of this instru-mentation channel. The inspector determined that 1) the erratic behavior of the channel started on December 26, 1985, and 2) Main-tenance Request (MR) 85-1664 was issued on December 27, 1985 to investigate the channel's erratic behavio On December 31, 1985, at 10:45 a.m., the Radiation Protection De-

'

partment (RDP) performed Procedure OP-4801, Functional Test and Alarm Settings of the Process Radiation Monitoring System, on the subject channel. This channel failed to meet the acceptance criteria

! and was declared inoperable. Up until this time the plant operators had been treating the channel as operable, as evidenced by the channel check logs and shift turnover logs for December 26-31, 1985, which indicated that no off-normal channel behavior existed. Once l the channel was declared inoperable, the licensee implemented Action

, Statement No. 14 as required by TS 3.3.3.1, Table 3.3.4, by in-l stalling a temporary continuous monitor within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Under MR l 85-1662, the licensee replaced a heat sensitive integrated circuit l in the channel, and declared the channel operable on January 3, 1986 following successful testing.

I Subsequent to the above observations, the inspecter discussed with the plant's Radiation Protection Manager and Technical Director his I concerns that control room operators and RDP technicians did not more aggressively question an obviously off-normal indicator, which when tested was found inoperable, and that meaningful qualitative )

j l

'

criteria does not exist for the operators to adequately assess the !

performance of an instrument during a channel chec l The licensee plans to to perform an evaluation of the No. 4 SG Blowdown Monitor recorder trace and recent Procedure OP-4801 test results for the period December 26-31, 1985, in order to assess the instrument's operability during this period. This item remains un- !

resolved pending further licensees actions (50-29/85-24-01).

'

b. System Alignment Inspection

)

Operating confirmation was made of selected piping system trains. Access-ible valve positions and status were examined. Power supply and breaker alignments were checked. Visual inspections of major components were performed. Operability of instruments essential to system performance

.

was assessed. The following systems were checked:

--

Charging System verified during control room board status review

--

l Emergency Diesel Generator (EDG) unit standby verified during tours of the EDG rooms and centrol room board status review l

.

.

--

Low and High Pressure Injection Systems verified during tours of the Safety Injection Building and control room board status review

--

Low Pressure Safety Injection Accumulator System during tours of the control room and Safety Injection Building c. Biweekly and Other Inspections During Plant tours, the inspector observed shift turnovers; compared boric acid tank samples and tank levels to the Technical Specifica-tion; and reviewed the use of radiation work permits and Health Physics procedures. Area radiation and air monitor use and opera-i tional status were reviewed. Verification of tagouts indicated the l action was properly conducted. There were no inspector identified deficiencies in this are . Observations of Physical Security Selected aspects of plant security were reviewed during regular and backshift hours to verify that controls were in accordance with the security plan and approved procedures. This review included the following security measures: guard staffing; random observations of the alarm stations; verification of physical barrier integrity in the protected and vital areas; verification that isolation zones were maintained; and implementation of access controls, including identification, authorization, badging, escorting, personnel and vehicle searches and compensatory measures when require The inspector has observed an increased involvement and effective-ness of the Security Supervisor in resolving in a timely manner licensee identified security system / equipment deficiencie The only deficiency noted during the inspection period involved the placement of snow by a licensee contractor within the inner isola-tion zones of the protected area (based on the security plan, no storage is allowed within the isolation zone). This occurred during i

I a weekend snow storm and reflected a lack of active involvement by the security organization providing guidance to the contractor per-sonnel involved in the snow removal effort. The inspector held a discussion with the Security Supervisor on December 18, 1985 and requested that the licensee initiate immediate corrective actio l The inspector verified that the licensee removed the snow placed in the isolation zone, and determined that corrective measures were taken that would ensure the active involvement of the Security Shift i Personnel in supervising the maintenance of the isolation zone dur-l ing snow removal operations at the site. The inspector had no fur-l ther questions on this item.

!

{

l

!

l I

o

]

.

7 Fire Protection and Housekeeping Directly following the refueling outage, the licensee initiated a significant cleanup effort to return the plant to pre-outage condi-tions that are reflective of the strong licensee commitment to maintaining a high standard of performance in the housekeeping are On November 30, 1985, the licensee completed Procedure OP-2112, Rev. 8, Operator's Vapor Container Housekeeping Inspection. This inspection is required by TS 4.5.2.c, and consists of a visual in-spectiun to verify that loose debris (rags, trash, clothing, etc.),

which could be transported to the containment sump and cause re-striction of the ECCS pump suctions during LOCA conditions, is not present in the containmen No violations were identifie . Bimonthly Safety System Walkdown The inspector independently verified the operability of a selected engineered safety feature (ESF) system by performing a complete walkdown of the access-ible portions of the system to:

--

Confirm that the licensee's system lineup procedures match plant drawings and the as-built configurations;

--

Identify equipment conditions and items that might degrade performance;

--

Inspect equipment and cabinets for abnormal conditions;

--

Verify proper valve position, availability for function and position indication; and

--

Verify compliance with Technical Specification requirement The Low Pressure Safety Injection Accumulator System was examined. All applic-able specifications of TS 3.5.1.a g were verified to be acceptable. Discus-sions with plant operators indicated that they were fully knowledgeable of the system design and operation. Inspection of the system revealed that all the valves examined were properly positioned and that the system was well maintaine Furthermore, the system appeared to be in a stand-by status cap-able of performing its intended functio The inspector also reviewed the licensee's actions in determining operability of the 500 psig Nitrogen Low Level Venting Subsystem and the 100 psig Nitrogen Cover Pressure Actuation Subsystem. The inspector noted that the Primary Auxiliary Operator (PAO) Log Sheet 1) had incorrect information on the minimum acceptable value for the 500 psig nitrogen supply bottle, and 2) did not pro-vide for checking the minimum or maximum regulated pressure values on either subsystem. This condition was brought to the attention of Operations Depart-ment managers. The licensee initiated an immediate change to the PA0 Log Sheet

_ _ - .

,

.

.

<

(Rev. 22) that provided the necessary clarifications and information. The

, licensee's actions were determined by the inspector to be fully responsive to NRC concerns on this matte During the system walkdown, the inspector noticed a nitrogen bottle that was installed downstream of pressure regulating valve SI-PR-58. The bottle was held in place by a rope attached to an adjacent I-Beam. The inspector ques-tioned the function of this bottle in the system. In addition, the inspector noted that safety class drawing M-7, which shows the safety classifications and boundaries on the Safety Injection System, did not show that this bottle was installed. According to the licensee, the bottle was installed in approx-imately 1978, as an expansion tank that would provide additional volume be-tween the SI-PR-58 pressure regulating valve and the downstream, normally-closet trip valve SI-TV-605. The I & C Supervisor indicated that this partic- '

ular pressure regulating valve, which is one of three installed in parallel, required the additional volume to regulate properly. The licensee could not provide the details of the expansion tank's installation or a reason as to i

why the pressure regulating valve could not be fixed or adjusted to function i without the added volume, as in the case of the other two valve l The licensee has since installed a permanent holding mechanism for the nitro-gen bottle that acts as an expansion tank and has taken steps to update the safety class drawing M-7 to show the expansion tank. The licensee has also i committed to reviewing the design details and circumstances that necessitates '

an expansion tank to allow pressure regulating valve SI-PR-58 to function properly. The inspector will follow this last item in a future inspection (50-29/85-24-02).

I Radiological Controls Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices, conformance to radio-logical control procedures and 10 CFR Part 20 requirements, were observe i Independent surveys of radiological boundaries and random surveys of non- !

radiological areas throughout the facility were taken by the inspecto !

Inspector observations and review of an event relating to radiological con-trols are contained below:

On December 3, 1985, the inspector observed a licensee-owned vehicle exit the '

Radiation Control Area (RCA) via a posted boundary gate within the Protected Area. However, the inspector did not observe Radiation Frotection Department

'

(RPD) involvement, and therefore, interviewed the two maintenance contractor employees riding in the vehicle. The inspectcr determined that contrary to the posted instruction, licensee practices, and procedural instructions there were no access controls employed by these individuals to prevent the potential spread of contamination outside the RC .

.

i Following the inspector's observation and request for corrective action, the vehicle was surveyed by RPD technicians. No contamination was discovere The RPD Manager issued a Radiological Deficiency-Report, which documents that the individuals involved have been re-instructed in the requirements of having their vehicle released from the RC The inspector noted that this occurrence was treated by the RPD Manager, Maintenance Department Manager, and the Senior Station Managers with an ap-propriate level of concern that resulted in their immediate attention to this matter. Furthermore, there was strong evidence of interdepartmental support for personnel compliance with established radiation protection practices. This note worthy support appears to be a building trend, with the inspector attri-1 buting this condition to the ability of the RPD manager to elicit cooperation i between his and other plant department Based upon routine observations associated with the licensee's performance ,

in implementing access controls for the RCA, this occurrence was judged by the inspector to be an isolated incident. The inspector had no further ques-tions on this matte . Review of Events Requiring Telephone Notification to the NRC The circumstances surrounding the following events, which required NRC noti-fication via the dedicated ENS-line, were reviewed. A summary of the inspec-tor's review findings follows or is documented elsewhere as noted below:

--

At 11:15 p.m. on December 1,1985, the NRC was notified in accordance with 50.72 (b)(2)(iii)(A) that the Channel 7 and 8 Power Range Nuclear Instrumentation low power trip setpoint input to the Reactor Protection System (RPS) exceeded TS 2.2-1 requirements. This event is discussed as part of inspector follcwup of LER 85-07 in Section 7.a of this repor At 12:16 p.m. on December 9,1985, the NRC was notified in accordance with 50.72 (b)(2)(ii) of an inadvertent reactor scram from Mode 2 as a result of a contractor employee _ bumping RPS relay K53A while vacuum cleaning inside the control room's Main Control Board. The individual was reinstructed in care of work practices. The licensee considers this event an isolated incident, with no further corrective actions determined to be necessary. This event will be the subject of LER 50-29/85-0 At 2:15 p.m. on December 28, 1985, the NRC was notified in accordance with 50.72 (b)(2)(ii) of an inadvertent reactor' scram from Mode 2 due to a false high startup rate trip input to the RP This trip was in-duced as a result of maintenance being performed on the Channel 3 Inter-

mediate Range Nuclear Instrumentation Caannel. This event is discussed in Section 7.b of this repor I -( <l

!

- - _ - _ _ ___ __ _ __ _ _.._ _ ._ __ _ _

q

'

-

-j

- 10 - '

L j ' Inspector Review Of Plant Events i

! - Cycle XVII-XVIII Refuelino Operations and Plant Startup i

I

--

At the beginning of.this inspection period, the licensee was nearing o the end of its refueling outage and was preparing to return the-

, plant to an operational status. Plant heatup to Mode 4 was. initiated on December 2, 1985. Initial. criticality of Core XVIII was achieved per OP-2103, Reactor Startup and Shutdown, and OP-1701, Core XVIII BOL Zero Pcwer Physics test. The measured Critical, Boron Concentra .

' tion at hot zero power with all rods out was 2089 ppa, which was i

within +/- 10% of the calculated design value (2060b ppa) and within the. acceptance criteria of the applicable operating procedure. At .

i 10:00 a.m. cn December 7, 1985,.the Reactor Engineering Department completed all'Startup Physics testing and, following data reductions

] and review, determined that all tested parameters met required j

.-

acceptance criteri ;

--

On December 1, 1985~at 10:30 p.m., with the plant in Mode 5 and OP-

4645, Nuclear Instrumentation Channel Calibration, bein'g performed, ,

the licensee determined that nuclear instrumentation power. range channels 7 and 8 exceeded the TS 2.2-1 low power range trip ~setpoint.

,

! The licensee attributed this event to two cold solder joints on the

! terminals of relay k1301, which resulted in a failure ofithe two <

,

channels to switch from the high power scram setpoint to the: low-a power setpoint upon actuation of a manual power scram set switc The licensee repaired the cold solder joints and inspected the re-maining terminals on relays k1301 and k1302. 'The licensee indicated that because the low power setpoint trip featu're.of the RPS requires

a 2 out of 3 channel trip condition to initiate a scram, the oper-ability requirements for Channels 7 and 8 low power set point'may

' not have been met. Because of this concern,'the ins'pector-reviewed plant operations subsequent to the last operability check of this j

,

trip function (which was a pre-critical check per OP-4611, Nuclear Instrumentation and Reactor Protection System Pre-Critical Check, 4

conducted on November 13,1984). The inspector' determined that ,

1) since the trip function is required when the plant power level

is less than or equal to 15 MWe, it was only during plant shutdown for refueling on October 19, 1985 that_the TS required protection

may not have been provided, and 2) the licensee does not take credit i i for this trip in it's accident analysi On December 3, 1985, the inspector. discovered that the quarterly

channel calibration and monthly channel functional test performed on power range channels 6, 7,_and 8 per Procedure OP-4601 did not -

,

' include testing the low power setpoint trip function. This condition .

is contrary to TS.4.'3.1'.1,~ Table 4.3 -1.-The inspector determined that although this may be a TS, requirement, conducting the monthly

, functional check for the.1ow power setpoint trip would result:in a plant trip. This discrepancy was$immediately brought to the at-

,

!

_ . , , - .- , - , - . - - .-. _ . - - _ _ , - - - _ _ . , _ - ~ - . . . . , - - . -

m . . _-- . . _ ._ ,

.

.

tention of the Plant Superintendent, who committed to changing the TS to clarify the testability of the low power setpoint tri The licensee issued LER 50-29/85-07 to document both the event and the immediate and long term corrective measures, which included its intent to submit a YS change for the surveillance clarificatio The inspector had no further questions on this even Power Operations

--

On December 10, 1985, the plant entered Mode 1, and the licensee placed the generator on the gri On December 28,1985 at 00:01 a.m. , the plant initiated a load re-duction from 98% power to remove the turbine from service and place the plant in Mode 2. This action was taken principally to perform maintenance on the turbine's No. 3 Control Valve that had stuck closed on December 13, 1985 and was limiting the plant from achiev-ing full power. Additional maintenance and inspection activities included 1) inspection of the right hand moisture separator drain check valve and moisture _ separator internals, 2) repacking of the No. 1 Heater Drain Pump, 3) inspection of east and west condenser waterboxes, 4) and repair of generator hydrogen leak At 1:29 p.m. on December 28, 1985, a reactor scram occurred due to a false High Startup Rate Trip. This trip was induced as a result of maintenance being performed on the No. 3 Intermediate Range Nuc-lear Instrumentation Channel. No abnormal plant or equipment re-sponses were noted as a result of the trip. Following a December 29, 1985 start of the No. 3 Boiler Feedwater Pump (BFP), at approxi-mately 7:20 a.m. the pump tripped on electrical overload, The lic-ensee determined that the pump and motor were. damaged and is inves-tigating this incident. The inspector noted that this pump underwent a complete overhaul during the recent outage.-The Plant was started up and phased onto the grid at 1:50 p.m. on December 29, 198 A main coolant system sample taken at 7:00 p.m. on December 29, 1985 showed a 74% of TS limit DEI level which occurred subsequent to a reactor power increase from 10-40% of rated power over a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period. By 8:00 a.m. on December 30, 1985 the DEI level was less than 20% and decreasing. Subsequently on January 4, 1985 the N ~

3 BFP was returned to service and plant load increased at a rate of 2% per hour. The DEI level was 3.9% of TS limit at that tim The licensee is conducting evaluations of the DEI transient and the failure of the No. 3 BF . Monthly Maintenance The inspector observed and reviewed maintenance and problem investigation ac-tivities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC. involvement, safety tag use,

-

_ ._ . . .. .

. . . _ . . . _ _ . . . .

'

,

-

,

l 12

i equipment alignment, jumper use, personnel qualification, radiological con-

trols for worker protection, fire protection, retest requirements, and re- -

portability per Technical Specifications. The following activities were in-cluded:

'

--

Maintenance Request (MR) 85-1435 Debris on the Tube Sheet of the No. 3 '

Steam Generator

--

MR 85-1474 Nuclear Instrumentation. Power Range Channels 7 & 8 Failed Surveillance Check of Low Power Setp int Trip (OP-4645)

--

MR 85-1496 PR-ZI-2 Acoustic Accelerometer for PR-SV-181 Failed Channe Calibration

--

MR 85-1583 Nuclear Instrumentation Channel 3 Indicates High

--

MR 85-1627 No Speed Control for the No. 3 Charging Pump J

l

--

MR 85-1656 Nuclear Instrumentation Channel 4 Log Level in Main Control j Board and FN Panel Disagree

--

MR 86-7, Intermediate Range Channel No. 3 Start Up Rate Alarm Relay Did

Not Operate At The Required Setpoint f i

i Regarding MR 86-7, the licensee determined while performing the monthly func-i tionel surveillance test per OP-4601, Rev. 15, Nuclear Instrumentation Chan-nels Functional Test, that the Startup Rate alarm circuit associated with the

~

.

Intermediate Range Channel 3 instrumentation was inoperative. Upon tapping the associated relay, the alarm function operated. Repeated efforts to repro-j duce-the failure were unsuccessful. The alarm function of the Intermediate Range Channels is not a TS requirement; however,.the'high startup rate annun-ciator circuit is automatically bypassed when plant power output is greater than 15 MWe. While the plant is at power,-the physical arrangement of the I

equipment precludes further maintenance activities because a high probability

! exists that these activities would cause a reactor trip. The licensee is ~

!

~

maintaining this MR in an open status pending further investigation'and/or- ,

surveillance testing results. No 10 CFR 50.59 concerns were identified by the

inspector as a result of' reviewing this' occurrence.

(

No discrepancies were identified during the inspector's review of this area.

9. Plant Information Reports (PIRs)

.

,

)

PIRs prepared by the licensee per AP-0004, Plant-Information Report, were re-viewed to determine whether-the conditions were reportable as defined in the -

.

TS and whether the licensee's system of problem identification and corrective action was being effectively utilized. The following PIRs were reviewed: :

i b

.

e -

, , + . , , - . ~ ~ - , _- e - ~ - w - , s.v, e+m , - , , , - -.,a- - +, , -

e

- . _

.

PIR N Occurrence Date Report Date Subject

85-5 5/2/85 5/28/85 Failure of RPS Main Coolant Piessure Channel Alarm & Trip Relay 85-7 7/18/85 9/27/85 Non-Return Valve (NRV) Main Steam Line Pressure Switch (MS-PS-11)

Failed Routine Surveillance 85-8 7/23/85 8/28/85 Loss t' Meteorological Data Sys-tem Primary and Backup Differen-tial Temperature Indication 85-9 8/16/85 9/17/85 NRV Main Steam Line Pressure Switch (MS-PS-31) Failed Routine Surveillance Except for the following comments, the inspector had no further question PIR 85-7 and 85-9: These events were reviewed in Inspection Report 50-29/85-1 The failure of the ASCO Tripoint Model TL10A22 continues to be both an open issue and a potentially reportable event under 10 CFR 21. This item will be reviewed via Inspector Follow Item 50-29/85-15-0 PIR 85-08: This event was reviewed in Inspection Report 50-29/85-14. It was noted that the cause of the occurrence was determined and appropriate _short and long term corrective actions were specifie . Cold Weather Preparations The inspector reviewad implementation of the licensee's program on extreme cold weather protective measures to determine whether the licensee has 1) in-spected systems susceptible to freezing to ensure the presence and operability of heat tracing, space heaters, and/or insulation; 2) set the thermostats

properly; and 3) energized the heat tracing and space heating circuit In preparing the plant for cold weather operation, the Operations Department implements OP-2115, Rev. 9, Warm or Cold Weather Operations. The inspector determined that this procedure was completed by the licensee on November 14, 1985. To ensure the operability of the plant's heat tracing systems, the Maintenance Department implements OP-5751, Rev. 8, Heat Tracing Inspections, which was verified by the inspector to be completed on October 1, 1985. A review of this procedure showed that no discrepancies existed; however, the shift supervisor was not notified of the completion of OP-5751 until November 6, 1985, and the completed procedure was not reviewed by the Maintenance Supervisor until December 3, 1985. Additional attention by licensee managemen to ensure timely notifications and reviews of completed maintenance activities is warranted to further ensure that such activities are conducted and com-pleted as require _ - -

-

I

-

i

. 14 (

Throughout the cold weather period, the Auxiliary Operators for the primary and secondary sides of the plant perform routine shift checks on the status of the heat trace and heating of systems and structures. The inspector re-viewed the PA0 and SAO Log Sheets regularly and verified these routine acti-vities were being accomplished. The licensee's actions associated with cold weather, preparations were determined to be performed in accordance with ap-proved plant procedures and consistent with commitments made in its response to IE Bulletin No. 79-24, Frozen Lines (WYR 79-223, October 10,1979).

Additionally, the inspector reviewed plant reporting records, determined that

events involving frozen systems or components are infrequent, and when they do occur result in corrective action to preclude recurrence.

l No violations were identifie . Review of Licensee Event Reports (LERs)

i LERs submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of cor- l rective action. The inspector determined whether further information was re- I l

quired from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed.

l LER N Event Date Report-Date Subject j 50-29/83-13 Rev. 1 4/13/83 12/2/85 Low Temperature Overpressure Protection (LTOP)

50-29/85-01 Rev. 0 5/13/85 6/14/85 Determination of Inappro-priate LOCA Methodology Rev. 1 5/13/85 12/16/85 Assumption 50-29/85-02 5/24/85 6/21/85 CS-V-621 Not Tested In Accordance With The ISI Program 50-29/85-03 11/5/85 12/5/85 Fuel Degradation 50-29/85-04 11/6/85 12/6/85 Main Coolant System Safety l

l Valve, PR-SV-181, Setpoint )

Greater Than TS Limit i

_

l 50-29/85-07 12/1/85 1/3/85 Nuclear Instrumentation {

Channels 7 and 8 Low Power i Set Points Inoperative j LER 50-29/83-13 was reviewed in Inspection Reports 50-29/83-06, 50-29/

85-04, and 50-29/85-14. This revision to the LER reflects a July 19, 1985 {

request by the inspector for the licensee to develop and submit a revised LER on the LTOP issue based upon their July 10, 1985 letter to NRC:NRR {

l

!

..

.

Although the licensee incorrectly referenced an April 23, 1984 letter to the NRC as the basis for this LER update, the material contained in the revision accurately reflects the latest information on this issu The inspector learned from a discussion with the NRC:NRR Project Manager that this item is being tracked by the NRC's' Licensing Action Reporting System, and an updated NRC Safety Evaluation will be issued. . The in-spector had no further questions on this item, and considers this LER close b. LER 50-29/85-01, Determination of Inappropriate LOCA Methodology Assump-tion. Documentation of the licensee's corrective actions and inspection findings, in part, is contained in Section 7.c of Inspection Report 50-29/85-11. This issue was subsequently discussed at a meeting with licen-see representatives to review ECCS code revisions and assumptions. This meeting, held at NRC:NRR offices on August 8, 1985, was attended by the inspecto The licensee provided a discussion of the administrative controls cur-rently in place at Yankee to provide assurance that the requirements of 10 CFR 50.46 are met with the current code for Cycle 17. The licensee has added administrative controls to limit control rod movement. These controls limit power levels in the upper core region, thereby limiting any top peaked power distribution. In addition, current TS have a re-striction on how soon after a power reduction the core can be returned to full power if the rod heights are outside the rod insertion limit, and a restriction on rod reactivity transient rates. Both of these TS restrictions serve to limit the effect of xenon transients on the axial flux distribution. The licensee has stated that the additional restric-tion on rod withdrawal limits will remain in effect until reaching 80%

power during power coastdown. Compensation for xenon transients will be accomplished using boron, to keep the rods within the administrative restrictio Since the licensee planned to implement changes in its operating re-strictions associated with control rod movement (these changes being different than those specified in the original LER), the inspector re-quested that an update to the LER be submitted. Revision I to the LER is fully responsive to the inspector's request and details the results of applicable licensee and NRC evaluations. The inspector verified that the licensee commitments to operate within more restrictive control rod limits were followe c. LER 50-29/85-02, Valve CS-V-621 not tested in accordance with the ISI Program. Documentation of the licer.see's corrective actions and inspec-tion findings is contained in Inspection Report 50-29/85-11, Appendix A.

.

e

.. .  ;

. ..

. LER 50-29/85-03, Fuel Degradation (Assemblies B-696 I, B-688 and A-679 In Core Positions C-9, H-8, and K-5). - Documentation of the licensee's corrective actions and inspection findings is contained in Inspection Report 50-29/85-18, Section LER 50-29/85-04, PR-SV-181 (Serial No. BW 07972) Setpoint Greater than Technical Specifications. The licensee w'as informed by its contracted test facility that the as-found setpoint of the low set Main Coolant System Pressurizer Code Safety Valve was 2603 psig,- which exceeds the T.S. 3.4.3.a lift setpoint limit (2485 +/- 3% psig) by 4.75%. This low set safety valve and one high set safety valve had been installed during the 1984 refueling outage. (This is the licensee's first experience with testing these new valves that are traceable to the industry sponsored program involving TMI Action Plan Item II.D.I.) A spare safety valve,

,

'

which was set and tested as a low set code safety valve, was installed in lieu of the PR-SV-181 valve removed and tested during the latest re-fueling outage. In addition, the licensee performed an analysis of the limiting overpressure event (loss of load transient) using the as-found-setpoint of PR-SV-181 with the high set PR-SV-182 safety valve disable The results indicate the peak primary and secondary pressures would not exceed 110% of design. In addition, an investigation into the effect of

,

,

'

further increases in the setpoint of the low set safety valve to 2750 psia resulted in acceptable result The licensee has attributed this event to setpoint drift,.with a further

investigation being performed. Currently the valve.in question has been reset to the high set safety valve setpoint with test results obtained that are within the TS specified set pressure toleranc This LER remains open pending further licensee action and subsequent NRC review. The inspector considers this event to be a licensee identified violation, and in accordance with the provisions of 10 CFR 2, Appendix C, a notice of violation will not be issue LER 50-29/85-07 This LER is reviewed in Section 7.A of this repor . Monthly Surveillance Observation The inspector observed tests and parts of tests to assess performance in ac-cordance with approved procedures and LCOs, test results (if completed), re-moval and restoration of equipment, and deficiency review and resolution. The follcwing tests were reviewed:

--

OP-4601, Rev. O, Nuclear Instrumentation Channels Functional Test

--

OP-4645, Rev. 3, Nuclear Instrumentation Calibration

--

OP-6464, Rev. 4, LPSI Accumulator Pressure Channel SI-P-5 Calibration

--

,

OP-4270, Rev. 2, Containment Drain Tank Level Monitoring i

a

.. 1

,

--

OP-4261, Rev. 4, Main Steam Operability Test

--

OP-4200, Rev. 11, Main Coolant System Leak Inspection & ISI Pressure Test No inadequacies were discovere . Onsite Review Committee On November 29 and December 6 and 31, 1985 the inspector observed the meetings-of the Yankee NPS onsite review committee (PORC) to ascertain that the pro-visions of TS 6.5.1. were me No unacceptable conditions were identifie . Management Meetings During the inspection period, the following management meetings were conducted or attended by the inspector as noted below:

--

The inspector attended daily exit meetings during December 16-19, 1985, and on December 20, 1985 at the conclusion of Inspection 50-29/85-25, Appendix R Safe Shutdown, onsite team inspectio The inspector attended a meeting on December 27, 1985 held by the cogni-zant NRC: Region I Section Chief with the licensee's.on-site manager This meeting was held to discuss the NRC's inspection program and items of mutual interes At periodic intervals during the course of the inspection period, meet-ings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspecto