IR 05000029/1985011

Insp Rept 50-029/85-11 on 850506-0610.No Violation Noted. Major Areas Inspected:Previous Findings,Operational Safety Verification Reviews,Bimonthly Safety Sys Walkdown,Plant Events & Emergency Planning Drill

ML20129D085
Person / Time
Site:	Yankee Rowe
Issue date:	07/03/1985
From:	Eichenholz H, Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20129D069	List: IR 05000029/1985011 ML20129D063
References
50-029-85-11, 50-29-85-11, NUDOCS 8507160415
Download: ML20129D085 (22)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /85-11 Docket N Licensee N DPR-3 Licensee: Yankee Atomic Electric Company 1671 Worcester Road Framingham, Massachusetts 01701 Facility Name: Yankee Nuclear Power Station Inspection at: Rowe, Massachusetts Inspection Conducted: May 6 - Juffe'10,1985 Inspector: ff f / 11. Eichen enior Resident Inspector date Approved By: *

T. Elsasse y Section Chief, Reactor date Projects Section 3C Inspection Summary: Inspection on May 6 - June 10, 1985 (Report No. 50-29/85-11)

Areas Inspected: Routine onsite regular and backshift inspection by the resident inspector (141 hours0.00163 days <br />0.0392 hours <br />2.331349e-4 weeks <br />5.36505e-5 months <br />). Areas inspected included: Review of licensee action on pre-vious findings, operational safety verification reviews, bi-monthly safety system walkdown, review of events requiring telephone notification to the NRC, review of plant events, surveillance observations, review of radiological controls, main-tenance observations, Plant Operations Review Committee activities, review of the Emergency Planning Drill, review of the potential for overpressurization of ECCS, and survey of the licensee's response to selected safety issue Results: No violations were inspector identified; however, two inadequacies in-volving the ISI Program (Appendix A) and procedure review practices (Section 13)

were classified as licensee identified violations. Licensee responsiveness to NRC review and initiative involving a modification to the station battery rooms was considered a notable strength (Section 13). Several areas needing increased licen-see attention were: adherence to surveillance review requirements (Section 8) and upgrading of inadequate radiatior. protection department procedures (Section 8).

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DETAILS 1. Persons Contacted Plant Operations B. Drawbridge, Assistant Plant Superintendent T. Henderson, Technical Director N. St. Laurent, Plant Superintendent

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The inspector also interviewed other licensee employees during the inspection, l including members of the Operations, Radiation Protection, Chemistry, Instru- i ment and Control, Maintenance, Reactor Engineering, Security, Training, Tech-nical Services, and General Office Staff . Summary of Facility Activities On April 26, 1985, the plant was at full power. A leak was discovered on the No. 1 extraction steam line on April 27, 1985 which resulted in a load reduc-tion to 15 MWe to facilitate repairs. Power was then increased on April 28, 1985, with the load increase being secured at 176 MWe on April 29, 1985 due to a second steam leak which occurred on the extraction steam line to the No.

i 1 feedwater heater. Following these repairs, the plant was increased to full l

power. The plant remained at essentially full power until May 4, 1985 when a load reduction to 50% power was initiated to facilitate turbine throttle

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valve testing and condenser tube cleaning operations. A load increase was in-itiated on May 6, 1985 and full power achieved on May 7, 1985. For the re-mainder of the period the plant was at essentially full power, other than minor restrictions that resulted from increased cooling pond water temperature j with it's attendant elevated condenser circulating water discharge temperature.

i The licensee determined on May 13, 1985 that a control rod movement restric-tion was required to provide compliance with the performance requirements of L 10 CFR 50.46. Details of this event are provided in Section 7 of this report.

l-l At the completion of this inspection period, the plant has been in continuous L operation for 206 days.

< 3. Licensee Action on Previous Inspection Findings (Closed) Inspector Follow Item (50-29/84-13-03). The licensee was to revise OP-2001, Responsibilities and Authorities of Operations Department Personnel, to clarify the review responsibilities of the Shift Supervisor related to completed surveillances on his shift. The inspector reviewed Revision 15 to AP-2001 and noted that it provided the necessary clarification. This item is close (Closed) Inspector Follow Item (50-29/84-20-05). This item required the lic-ensee to provide the basis for excluding eight valves from a one time demon-stration test for Systematic Evaluation Program (SEP) Topic III-IO.A, Bypass

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of Thermal-0verload Devices. Licensee letter FYR 85-47 to NRC:NRR dated April 25, 1985 specified that the subject overloads were not previously included in the submittal because of their association with other plant modification However, they were tested during installation and will be retested during the 1985 refueling outage for comple.teness of the SEP topic. This item is close (Closed) Inspector Follow Item (50-29/84-20-06). This item involved SEP Topic VI-1, Surface Coating Inspection Program, and required a licensee information submittal to NRC:NRR and verification that the on-site inspection was consis-tent with the submittal. In the above enumerated licensee letter, the licensee described it's documented paint inspection program. The inspector verified that the onsite inspection was consistent with the described program. This item is close (0 pen) Inspector Follow Item 50-29/84-20-09) Follow Dose Equivalent Iodine (DEI) levels due to apparent fuel cladding failure in core XVII. During the period of April 27 to June 10, 1985, fluctuations in DEI were noted to vary from 8.8% to 25% of tha allowable TS limit. The licensee continues to maintain maximum bleed, purification, and changing flow rates (50 GPM) to maintain the steady state DEI levels at a minimu (Closed) Inspector Follow Item (50-29/85-04-02) This item required the licensee to submit a revised Proposed Change to the Technical Specifica-tions to address SEP Topic XV-19, ECCS subsystem leakage limits outside containment. On May 7, 1985, the licensee submitted Proposed Cbsnge N (FYR 85-54) to NRC:NRR, which contained a 50 gal per-day proposed limit to be included in Technical Specification (TS) 3.5.5/4.5.5. This item is close . Operational Safety Verification Reviews Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's, instrumentation, rect,.

der traces, protective systems, control rod positions, Containment tem-perature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source operability, control room and shift supervisor logs, tagout logs, and operating order (1) On May 14, 1985, the inspector observed that the Pressurizer Wide Range Level indicator, PR-LI-705, was indicating 105 inches. Other indication channels were providing pressurizer level values between 120 and 123 inches. The licensee issued Maintenance Request (MR)85-158 on February 7, 1985 as a shutdown required item to provide resolution of the apparent indicator anomaly. The onshift licensed operational personnel and I&C foreman could not readily identify for the inspector the applicability of the TSs to the subject in-strument channel. Following a review of surveillance procedures, the licensee identified that the instrument channel was one of the two required Accident Monitoring Instruments required for pressur-izer water level in accordance with TS 3.3. r

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The inspector noted that there was an apparent lack of information and guidance available to the operators on what are acceptable operational discrepancies between the channels that monitor the pressurizer water level. Futhermore, station personnel were unable to identify for the inspector the acceptable error band for the PR-LI-705 instrument channel. The licensee considers the relative indication to be the important information being conveyed by this channe To demonstrate that the PR-LI-705 channel response was acceptable, on May 14, 1985 the licensee cycled pressurizer level. The. response for the three pressurizer water level channels, including PR-LI-705, demonstrated that there was close agreement between the indicated change on each channe No violations were identifie b. System Alignment Inspection Operating confirmation was made of selected piping system trains. Acces-sible valve positions and status were examined. Power supply and breaker alignment were checked. Visual inspections of major components were per-formed. Operability of instruments essential to system performance was assessed. The following systems were checked:

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Emergency Diesel Generator (EDG) unit standby verified during tours 1 of the EDG rooms and control room board status revie Charging System verified during control room board status revie Standby status of the Safety Injection Accumulator verified during tour of the accumulator room and control room board status revie Low and High Pressure Injection Systems verified during tours of the Safety Injection Building and control room board status revie Motor driven Emergency Feedwater Pump standby status verified during tour of the Primary Auxiliary Buildin No discrepancies were identifie c. Biweekly and other Inspections (1) 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-

< tional status was reviewed. Plant housekeeping and cleanlir.ess were evaluated. Verification of tagouts indicated the action was properly conducted. The inspector identified the following deficiency:

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During a tour of the Safety Injection Building on May 22, 1985, the inspector observed that various wiring prints were stored in the back compartments of the 480V Emergency Buses. The prints were labeled as uncontrolled documents. Inspector con-cerns related to the applicability of document control require-ments and the potential inadvertent use of out of date docu-ments were discussed with the Plant Maintenance Manager. Lic-ensee action to correct this condition consisted of 1) removal of the wiring prints, and 2) implementing standing instructions to maintenance personnel that when they discover similar con-ditions, to remove the prints unless they are being controlled in an approved manner. The inspector had no further question on this ite (2) Observations of Physical Security Checks were made to determine whether security conditions met regu-latory requirements, the physical security plan, and approved pro-cedures. Those checks included security staffing, protected and vital area barriers, vehicle searches, and personnel identification, access control, badging, and compensatory measures when require No violations were identifie . Bimonthly Safety System Walkdown In lieu of the normal Bimonthly Safety System Walkdown, a special inspection associated with potential overpressurization of Emergency Core Cooling Systems was conducted (see report Section 13). During the review the inspector deter-mined that the Low and High Pressure Injection Systems were operable, with no inadequacies identified as a result of this revie . Review of Events Requiring Telephone Notification to the NRC The circumstances surrounding the following event requiring NRC notification via the dedicated ENS-line was reviewed. A summary of the inspector's review findings follows:

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At 11:54 A.M. on May 13, 1985, the NRC was notified in accordance with 50.72(B)(1)(ii)(A) that the current loss of Coolant Accident analysis may not be in compliance with Section I.A of Appendix K to 10 CFR 50 pertaining to axial power distribution assumptions. The subject at this notification is discussed in additional detail in Section 7 of this re-por . Inspector Review of Plant Events On May 8, 1985, the licensee isolated the Condenser Steam Dump (MS-PCV-402) by closing the upstream isolation valve (AS-V-617). Operation of the plant with the turbine bypass line to the condenser isolated was

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initiated to eliminate leakage past the steam dump valve. The Operations Department issued Special Order No. 85-22 to the plant operators which

.provided procedure changes and the applicable safety evaluatio The inspector reviewed the safety evaluation and determined that the licensee had provided a written basis in accordance with 10CFR 50.59 (a)(2), that, operating the facility with the turbine bypass line to the condenser isolated is not an unreviewed safety question. Immediately following a plant trip, the isolation valve AS-V-617 will be opened to

. allow decay ~ heat removal. A~ licensee evaluation indicates that if the operator action is.taken within approximately five minutes after the plant trip, the main steam line safety valve setpoint should not be reached. The inspector had no further questions on this ite On May 13,1985 at 11:32 a.m. , the plant was informed by their Corporate Headquarters that the Loss of. Coolant Accident (LOCA) analysis may.not be in compliance with the requirements of Section I.A of Appendix K to

'10 CFR 50.46 pertaining to axial power distribution assumptions. At111:54 a.m., the licensee notified the inspector of the identified deficiency,.

and initiated a call to the NRC in~accordance with 50.72 (b)(1)(ii)(a).

To assure that the plant operation stays within analyzed conditions, a more restrictive control rod limit was immediately implemented that re-stricted Control Rod Group C withdrawal to 84 inches. This limit on-Group C operation served to keep power skewed away from the top of the cor Since core power distribution varies with core life, as well as control rod position, a further restriction that limited Group C withdrawal to 83 inches was implemented on June 6, 1985 prior to reaching a core ex-posure of 11,000 mwd /Mtu. The'need for further correction is being re-viewed _by the licensee. The inspector verified that revised procedural instructions were issued by the licensee providing the necessary actions to assure operators will maintain the plant within analyzed conditions.

- As a result of the NRC:NRR becoming aware of errors in the Exxon PWR LOCA analysis methods in March 1985, the_ licensee's-Nuclear Services Division (NSD) was requested to evaluate'NRC concerns regarding Exxon LOCA Analysis deficiencies. One concern was determined by the licensee to'be applicable. This dealt with the acceptability of the axial power distribution study which had been submitted in 1975 as required by Ap-pendix K. Although the NRC:NRR safety evaluation of December 4, 1975-reviewed and approved the LOCA analysis for the Yankee plant which used

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'the chopped-cosine power distribution, the validity of an Exxon assump-tion that the Westinghouse-derived K(Z) curve was applicable to the. Exxon fuel was now being questioned. NRC:NRR has concluded that no axial _ power shape sensitivity studies have been performed for the Yankee plant which support the use of the maximum linear heat generation rate at all core elevations.-Because the NRC:NRR does not have sufficient information to conclude that the plant remains in conformance with 10 CFR 50.46, and

, because the TSs may not be adequate, a request for information was transmitted to the licensee on May 22, 1985. The information, which is o

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to be submitted by the licensee by June 28, 1985, is to demonstrate that the current plant LOCA analysis and TSs conform to 10 CFR 50.46. Fur-thermore, if the licensee cannot provide the required demonstrations, they are to provide plans and a schedule for performing the analysis and TSs revie The licensee plans on issuing LER 50-29/85-01 to document the event. The inspector will continue to follow the licensee's corrective actions as part of LER followu . Monthly Surveillance Observation The inspector observed tests and parts of tests to assess performance in ac-cordance with approved procedures and LCO's, test results (if completed), re-moval and restoration of equipment, and deficiency review and resolution. The following tests were reviewed:

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OP-4606, Nuclear Instrumentation Channels Functional Test

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OP-4220, Primary System Water Balanc OP-4207, Weekly Surveillance Test of the No.1 Emergency Diesel Generator and the AC Power Distribution Syste OP-4204, Monthly Test of Safety Injection Train No. 3

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OP-4674, Process Radiation Monitoring Channels-Electronic Alignment

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OP-4801, Function Test and Alarm Setting of the Process Radiation Moni-toring System As a result of inspector review in this area, the inspector identified the following items:

(1) Regarding the performance of OP-4220,-Primary System Water Balance, the inspector noted on May 13, 1985 that the surveillance records associated with the procedure were being signed by licensed person-nel other than the Shift Supervisor (SS) which is contrary to the procedure's instruction. In addition, AP-2001, Rev. 15, Responsi-bilities and Authorities of Operations Department Personnel, clearly indicates that it is the shift supervisor who is responsible for the review of completed Operations Department procedures on his shif A review of completed OP-4220 surveillance records dating back to April 2, 1985 indicates that the identified inadequacy is more than an isolated occurrence. On April 2 and 4, 1985, the review signature of the surveillance was that of a licensed Reactor Operator who is in training for a Senior Reactor Operator's licens ;

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In Inspection Report 50-29/84-13, the inspector identified a similar occurrence and requested the licensee to initiate corrective meas-ures. These measures, identified by the licensee, included stipu-lating the review responsibility of the SS in procedure AP-200 A discussion of this issue was held by the inspector with the Plant Operations Manager (P0M) on May 13, 1985, who acknowledged the in-spector's comments and concerns. Immediately, the POM issued a de-partmental memorandum to each licensed operator that directs them to adhere to the applicable procedural requirement in AP-2001. The licensee was informed that further recurrence of the identified deficiency could result in enforcement actio (2) _ During the performance of OP-4204, Test or Special Operation of the Safety Injection Pumps and determination of ECCS Subsystem Leakage on May 30, 1985, the inspector observed erratic operation of the control room pressure indicator, SI-PI-6, that monitors the dis-charge pressure of the Low Pressure Safety Injection (LPSI). This indicator is utilized by the control room operator to verify pump performance. The inspector had difficulty in discerning whether the procedural acceptance criteria required by the TS 4.5.2.a.2.b. of greater than or equal to 250 psig was being met by the surveillanc In response to the inspector's questions, the control room operator obtained a value of 260 psig from the local pressure indicator being observed by the auxiliary operator that confirmed the pump was per-forming acceptabl The inspector recommended to the P0M that consideration be given to utilize local indication for discharge pressures associated with the LPSI pumps if it provides more reliable data. The licensee is-sued Maintenance Request 85-666 to correct the erratic operation of indicator SI-PI-6. The inspector had no further questions on this ite (3) On June 6, 1985, the inspector observed the performance of post work operability surveillance in accordance with OP-4801 following re-pairs to the No.1 Steam Generator Blowdown Monitor. This testing is necessary to determine operability prior to returning this TS required instrument to service. The inspector noted that the test did not meet the acceptance criteria and an adjustment to the in-strument's high voltage was required to achieve acceptable result When questioned about the instruction utilized to readjust the high voltage, the Radiation Protection (RP) Department Technician in-formed the inspector that he was complying with verbal instructions from a RP Engineer. The inspector determined that procedure OP-4801 neither prescribed instructions to the technicians for required

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actions if the acceptance criteria is not met while performing post work testing nor describes appropriate instructions for adjusting the instruments high voltag r

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l-Following identification of the inadequacy, the inspector held dis-

.cussions with the Radiation Protection Manager (RPM) on the issu In responding to the inspector's comments and concerns, the RPM concluded that' appropriate procedural controls should be developed to provide assurance that off-normal situations, including the event described above,-will result in acceptable corrective measures when performing 0P-4801. Weaknesses pertaining to poorly written proce-dures in the'RP area were identified in the recent-SALP Report-

.(50-29/85-99) as a.NRC concer ~

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According to the Plant's Technical Director, the necessity to obtain additional staffing to aid the ongoing RP area procedure review and upgrading process has been identified, and is currently receiving Senior Operational Management attention. The inspector will' follow the licensee's revision of OP-4801 that will prescribe actions re-quired if unacceptable test'results are obtained (50-29/84-11-01).

9. 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 Independent. surveys of radiological boundaries and random surveys of non-radiological points throughout the facility were taken by the inspecto On May 22, 1985, the inspector reviewed the licensee's practices and administrative controls applied to High Radiation Exclusion Area (HREA)

keys. These controls are contained in Procedure AP-8010, Rev. 4, High Radiation Area Control. Attachment B to the procedure specifies, in part, that keys to HREAs shall be under the administrative control of Radiation Protection Supervision (Administrative Controllers), and keys may be is-sued by the administrative controller or any individual designated on APF-8010.3 by the Plant Radiation Protection Manager (PPM).

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The inspector noted that form APF-8010.3, Designated Key Issuer Sheet,

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listed twel.ve individuals who are assigned access keys; however, four of them hav'e either left the licensee's employ or are no longer in the

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Radiation Protection Department. Each of the twelve individuals listed on form APR-8010.3 have a numbered key issued to them that provides ac-cess to the control point repository which contains a set of HREA key The licensee's cognizant Radiation Protection Engineer (RPE) demonstrated-accountability for the four errouneously assigned keys, initiated action to1 issue an updated form APF-8010.3 to reflect current designated indi-viduals who have the authority to use the key to the repository, and is-sued an updated key issue roster documenting the status of the keys is-sued to dat r

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Procedure AP-8010, Attachment C, requires an inventory of keys in the locked respository without specifying a frequency. According to the lic-ensee the inventory is conducted once per wee TS 6.12 specifies that keys to HREAs shall be maintained under the ad-ministrative control of the Shift Supervisor on duty and/or the Plant tiealth Physicist. In light of this requirement the inspector questioned the adequacy of the licensee's once per week inventory of the HREA keys and the apparent abundance of keys issued to Radiation Protection (RP)

Department personnel for access to the repository at the control poin In response to inspector concerns, the licensee's RPE issued a memorandum to all RP Shift technicians to perform and document an inventory of the repository as part of the shift relief routine. The inspector noted that this practice was subsequently formalized in procedure OP-8042, Rev. 1, Radiation Protection Shift Personnel Duties and Surveillances. Addition-ally, the licensee is reviewing it's practices and controls associated with the keys to the control point repository. The inspector noted that although Procedure AP-8010 contains instructions, including compensatory measures, detailing actions required for the loss of a HREA key, there are no controls established to deal with the loss of a repository access ke The acceptability of the licensee's practices and established admini-strative controls for HREA keys in considered an unresolved item pending further NRC review (50-29/85-11-02).

10. Monthly Maintenance Observation The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and mainten-ance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualification, radiological controls for worker protection, fire protection, retest requirements, and re-portability per Technical Specification. The following activities were in-clude MR 85-565, No. 1 Component Cooling Pump, Motor, and ACB Routine Inspec-tio MR 85-568, No. 1 Charging Pump-Excessive Leakag MRs85-568 and 668, No. 3 Charging Pump-Excessive Leakag MRs85-590, No. 4 Steam Generator Blowdown Monito MR 85-643, Trip Valve Position Indication Light Panel - Loss Of Indica-tio MR 85-666, Low Pressure Safety Injection D'ischarge Pressure Indicator SI-PI-6 Operates Errati r

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In addition to reviewing the above MRs, additional reviews relating to licen-see maintenance activities are contained in Sections 13 and 14 of this in-spection repor No inadequencies were identifie . Onsite Review Committee On May 22, June 4~, and June 10, 1985, the inspector observed meetings of the Yankee NPS onsite review committee (PORC) to ascertain that the provisions of TS 6.5.1. were me Except for the following items, the inspector had no further comments as a result of reviewing the licensee's activities associated with the onsite re-view committee:

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At PORC Meeting 85-20 on May 22, 1985, the licensee identified two situ-ations that involved failure to provide committee review of temporary changes to procedures within 14 days of initiation of the change. Com-mittee review requirements are stipulated in TS 6.8.4 and Station Proce-dure AP-0001. Following discussions with the licensee's Technical Direc-tor and Technical Services Supervisor, the inspector learned that these incidents were identified to be due to administrative oversights. Plant management plans corrective measures to preclude recurrence. Based upon the licensee identified cause of these occurrences, the inspector is treating this matter as a licensee identified violation in accordance with NRC guidance contained in 10 CFR 2, Appendix Engineering Design Change Request (EDCR)84-317, Masonry Wall Modifica-tions Inside the Turbine Building and Switchgear Room Jet Impingement Plate, was reviewed by the PORC at Meeting 85-23 on June 4, 1985.-The inspector observed a detailed and meaningful review of the proposed modification by the committee. Significant detailed comments resulted from the pre-PORC review of the EDCR by the Maintenance Support Depart-ment. Although the PORC considered the EDCR and Safety Evaluation ade-quate for preliminary construction activities, these documents were con-sidered to contain insufficient detail for contractor work in and around the battery rooms. Regarding work related to the battery rooms, the com-mittee made cogent comments pertaining to 1) restriction of the contrac-tor to work within one battery room at a time,~2) all shoring placed in the battery rooms to support the pouring of the roof slab to be analyzed and independently reviewed by YNSD Engineering befort placement of con-crete, and 3) 'the Safety Evaluation must be revised to address precau-tions taken while working in the switchgear and battery room Following the PORC Meeting, the inspector notified NRC: Region I of the licensee's plans to implement the EDCR during normal plant operation These plans included the pouring of a new concrete roof slab over the existing roof that covers both battery rooms. A concern was raised by NRC: Region I involving the potential difficulties in ensuring a plant

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shutdown if a catastrophic failure of the roof over the battery room occurred during modificatio This concern was transmitted by the in-spector to the Plant Maintenance Manager and Maintenance Support Depart-ment Supervisor following the completion of the inspection period, with the recommendation that the licensee consider either pouring the roof over one battery room at a time or consider delaying the pouring of the concrete roof until the plant is shutdown for refueling. The licensee demonstrated a cooperative approach in regard to the aforementioned NRC concerns by considering to review the matter and investigate alterna-tive Subsequently, the Plant Maintenance Manager informed the inspector that the licensee plans to pour the roof slab over one battery room at a tim The inspector had no further question on this matte . Emergency Planning Drill The inspector participated in the review of the licensee's Emergency Drill which took place on May 15, 1985. This review included three major areas:

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drill preparation / review of scenario l

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drill observance

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review of licensees critique / presentation of NRC finding The details of the inspector's comments and findings were presented to the NRC:RI team leader and will be described in NRC Inspection Report No. 50-29/

85-0 . Potential Overpressurization of ECCS A special limited inspection was conducted during this inspection period due to long-standing concerns of the NRC about the possibility of overpressurizing Emergency Core Cool.ing Systems. The scope and inspection findings are docu-mented in Appendix A of this inspection repor . Survey Of Licensee's Response to Selected Safety Issues-Steam Binding of Auxiliary Feedwater Pumps An inspection was conducted to determine the actions that the licensee has taken to address the safety issue of steam binding of auxiliary feedwater pumps due to back leakage. This issue has been identified in IE Information Notice 84-06 and in the Institute of Nuclear Power Operations' (INPO) Signi-ficant Operating Experience Report (50ER) 84-3. The primary purpose of the inspection is the gathering of information to be used in determining if NRC staff action is necessary on this safety issue. A secondary purpose of the inspection is to determine the actions that licensees at operating reactors are taking in response to recommendations to INP0's 50ER F 1

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The scope of inspection, as contained in Temporary Instruction 2515/67 of the NRC'.s I&E Manual, includes a determination as to whether procedures to prevent, detect, and correct backleakage have been implemented and whether personnel training has been scheduled. For those items that the licensee has not imple-mented, an alternate reason or justification was provided if documented by the licensee. All reported licensee actions were those implemented prior to April 1, 198 Inspection results are documented in Appendix B to this report and were sub-mitted to I&E for inclusion in their survey result . Managements Meetings During the inspection period, the following management meetings were conducted or attended by the inspector as noted below:

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The inspector attended an exit meeting held on May 10, 1985 by region based specialists at the conclusion of Inspection 50-29/85-09, Review of the licensee's Environmental and Personnel Monitoring TLD Progra The inspector participated in management meetings associated with the team inspection 50-29/85-08 of the licensee's Annual Emergency Plan Ex-ercise conducted during the period of May 13-16, 198 The inspector attended an exit meeting held on May 31, 1985 by region based specialists at the conclusion of Inspection 50-29/85-10, Review of the licensee's Radiological Environmental Monitoring Progra The inspector attended an exit meeting held on June 7, 1985 by a region based specialist at the conclusion of Inspection 50-29/85-13, Review of the licensee's construction activities associated with the Safe Shutdown System buildin 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 F

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APPENDIX A INSPECTION REGARDING POTENTIAL OVERPRESSURIZATION OF ECCS In accordance with the April 22, 1985 Memorandum from R. W. Starostecki, Director, Division of Reactor Projects, NRC-Region I to Resident Inspectors, a special limited inspection regarding potential overpressurization of Emergency Core Cooling Systems was conducted during the current inspection period. The scope of the in-spection included documenting the As-Built interface configuration; reviewing sur-veillance and maintenance procedures; verifying proper application of procedures; and determining if the licensee is addressing related failure experienc . The interacing systems reviewed were: Low Pressure Safety Injection (LPSI),

High Pressure Safety Injection (HPSI), and the Shutdown Cooling System (SCS).

Since NUREG/CR-2069 (Summary Report of a Survey of Light-Water-Reactor Safety Systems) did not contain YNPS's component configuration, the information of the type contained in this document is provided in Attachment YNPS was reviewed under the Systematic Evaluation Program (SEP), with the re- .

sults documented in NUREG-0825, dated June 1983. SEP Topics V-11-A and V-11-B, Requirements for Isolation of High and Low Pressure Systems and Residual Heat Removal System Interlock Requirements, respectively, were covered in the plant review. Details of the concerns and proposed modifications pertaining to potential SCS overpressurization are contained in NUREG-082 Attachment 1 depicts the valves that normally maintain isolation for each high/ low pressure interface. In addition, those valves that can be used to provide the isolation function are identified. Effectively, the LPSI and HPSI headers outside con-tainment are each protected from over pressurization by three check valves installed in high pressure piping within containmen . Surveillance activities applicable to the isolation valves in the LPSI and HPSI Systems were reviewed. The requirements for testing are specified in the TSs, and are associated with either containment isolation valve (CIV) leak rate determination (Appendix J) or ASME Section XI ISI Testing. The LPSI and HPSI header outboard isolation check valves (CS-V-621 and SI-V-14, respec-tively) are the only valves in these systems that are specified in TS Table 3.6-1, CIVs. However, they are exempt from Type C leak rate testing. Inser-vice Inspection and Testing program surveillance requirements are specified in TS 4.4.9.1 and 4.0.5. All check valves depicted in Attachment 2 are speci-fied as having inservice testing requirements in the program. During refueling outages the licensee conducts flow tests of the ECCS system to verify all check valves open to flow (procedures OP-4208 and OP-4206). The only valves in the program for the subject systems that are required to demonstrate back-flow isolation capability are the individual cold leg check valves closest to the loops (SI-V-18,19,20&21), and check valves CS-V-621 and SI-V-14. This testing is specified to be done during refueling, except that SI-V-14 is to have valve closure capability verified on a quarterly basis (actually tested on'e c per week using a differential pressure check per OP-4204).

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Appendix A 2 The ISI Program has taken exception to leak testing requirements for Section XI in favor of the leak testing requirements of Appendix J. This results in no leak testing being performed because of existing Appendix J exemption The pressure isolation valves (PIV'S) depicted on Attachment 2 are listed in the current program with a notation that the licensee is evaluating-the feasibility of performing leak testing. Currently, the licensee is pre-paring a program plan revision that takes credit for ongoing pressure moni-toring of the high pressure alarming device on the LPSI and HPSI Systems up-steam of these check valves which would alert the operators of a leaky check valve. According to the licensee's ISI Coordinator, this system meets the in-tent of ASME Section XI, IWV-3421. Based upon the established test methodology, there are no precautions / prerequisites necessary to prevent overpressurization of low pressure pipin On May 25, 1965, the licensee informed the inspector that the test used to verify closure of check valve CS-V-621 (pocedure OP-4204 once per week veri-fication of differential pressure indication following operation of a LPSI pump) was inadequate to demonstrate the once per refueling required test. Al-though the licensee has identified and documented an alternative test that verified valve cycling and closure which provides ISI program credit, they identified the event as an inadequency in procedural requirements. An LER will be submitted by the licensee to document the event and their prescribed cor-rective actions. In accordance with the criteria established in 10 CFR 2, Appendix C, this item is classified as a licensee identified violatio . The review of maintenance activities and practices that apply to the subject isolation valves resulted in identifying six specific events that occurred between 1974 and 198 Three of these events involved the LPSI header check valve CS-V-621, which involved valve cover weeping only. Two of the events involved two of the four downsteam cold leg check valves (SI-V-18 on July 1974 and SI-V-21 on July 1977) which involved leakage past the check valve sea Maintenance consisted of removal of clapper assembly, lapping the clapper and seat, and reassembling the valves. The final event involved internal valve inspection on the HPSI header check valve SI-V-14 per Information Notice 81-30 in 1982. No modifications or design changes of the isolation valves were identified by the inspector to have occurred at YNP From a review of licensee procedures, records, and personnel interviews the inspector could not identify any specified preventive maintenance and compo-nent rer .acement policies for the isolation valves. QC coverage during safety relattu maintenance activities are involved with document review and/or in-spection and/or audit of field documentation packages. Independent verifica-tion of maintenance activities is performed, but not on a 100% basis. YNPS utilizes Procedure OP-5104, Safety Related Valve Maintenance, as a routine maintenance procedure for work on the subject isolation valves. Requirements are stipulated for shift supervisor permission for release of equipment and identification of valves being utilized as isolating valves for plant and personnel safety. This procedure specifies that at the completion of mainten-ance work the valve has been returned to Operations Department control for the oerformance of post work testing. The Maintenance Request is utilized to document implemented post work testing and result r

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Appendix A .3 In approximately 14 years of operation of the current Safety Injection System, there appears to have been no instances of actual or potential overpressuri-zation of low pressure ECCS piping or component . In general, operations and maintenance personnel maintain a strong regard for adherence to surveillance and maintenance procedural controls. Plant operators are formally trained in their surveillance duties associated with the routine testing of the HPSI and LPSI isolation valves. Although a generalized proce-dure (0P-5104) is utilized by maintenance personnel anytime work is performed on the subject isolation check valves, formal training is provided in the proper use of this procedure. Operators were knowledgeable about the continu-ous leakage monitoring system, that provides warning of excessive back leakage through the isolation check valve In response to NRC dissemination of ap-plicable operating experience regarding previous isolation valve problems, the following licensee actions were noted:

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As a result of Information Notice No. 81-30, Velan Swing Check Valves, the licensee inspected the intervals of the two similar Velan check valves (one of which was SI-V-14: HPSI containment isolation check valve)

and concluded that the identified failures would not occur at YNP As a result IE Bulletin 79-04, Incorrect Weights for Swing Check Valves manufactured by Velan Engineering Corp. , the licensee determined that their installed Velon Check Valves utilized the correct weight Currently, Information Notice 84-74, Isolation of Reactor Coolant System from Low-Pressure Systems Outside Containment, is undergoing evaluation per Procedure AP-0020, Operating Information Review. The preliminary evaluation has concluded that the information has been adequately ad-dressed at YNPS; however, it was recommended to include the information in Maintenance Department training as a reminder of the importance of procedures, post installation testing and attention to detai . A review was conducted of the following industry wide experience related to isolation barrier failures:

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IE Information Notice No. 84-74, Isolation of Reactor Coolant System from Low-Pressure Systems Outside Containmen Report to Congress on Abnormal Occurrences 84-8, Degraded Isolation Valves in Emergency Core Cooling System NRC Office for Analysis and Evaluation of Operational Data Engineering Evaluation Report AE0D/E414, Stuck Open Isolation Check Valve on the Residual Heat Removal System of Hatch Unit No inadequacies or weaknesses in the current facility design or procedures were identified by the inspector that could lead to overpressurization events at the YNPS. However, reasonable assurance of isolation capability could be enhanced by implementing an appropriate preventative maintenance program on LPSI and HPSI header check valves (including the containment isolation valves).

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l ATTACHMENT 1 - YNPS CONFIG'JRATION (NUREG/CR-2069)

Plant No.:

Yankee Nuclear Power Station UNIT DESIGNATION (S) 1 DOCKET NUMBER (S) 29 COMMERCIAL OPERATION DATE (S) 7/1/61 REACTOR TYPE' PRESSURIZED WATER REACTOR POWER (MWT) 600 NSSS W

1. OF LOOPS 4 ARCHITECT-ENGINEER S&W CONTAINMENT TYPE STEEL SPHERICAL SHELL INTERFACING SYSTEM LOSS OF COOLANT ACCIDENT **************

' INTERFACING SYSTEM HPCI PIPING LOCATION IN NUMBER OF PENETRATIONS 1 Penetration Diameter 3 Inches R C S - MO V- C K- C K- C K- H/ L- I- P RV- C K- MOV- MV- C K- P LO - L0 LO LOW PRESSURE (PSIG) 1850 100 Deg. F HIGH PRESSURE (PSIG) 2300 550 Deg. F MONITORING PIND CR-PRESS IND & AL CR INTERFACING SYSTEM LPCI PIPING LOCATION IN NUMBER OF PENElsATIONS 1 Penetration Diameter 8 Inches COMPONENT LINE-UP CK-MV-CK-P R C S-MOV- C K- C K- MOV- C K- MOV- I- P RV- C K- MOV LO L0 L0 LO MOV-CK-ACC LO LOW PRESSURE (PSIG) 720 100 Deg. F HIGH PRESSURE (PSIG) 2300 550 Deg. F MONITORING PIND CR-PRESS IND&AL INTERFACING SYSTEM SCS-PIPING LOCATION IN NUMBER OF PENETRATIONS 1 Penetrations diameter 6 Inches COMPONENT LINE-UP u

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Attachment 1 .2 RCS- MOV- MOV- H/ L- I - P RV-HV- HX- MV- MO V- C K- P LC LC NC NC NC LOW PRESSURE (PSIG) 425 HIGH PRESSURE (PSIG) 2500

. MONITORING PRESS IND-PRINL INTERACING SYSTEM SCS PIPING LOCATION OUT NUMBER OF PENETRATIONS 1 Penetration Diameter 6 Inches RCS-MOV-MOV-H/L-I-PRV-MV-P LC LC NC LOW PRESSURE (PSIG) 425 HIGH PRESSURE (PSIG) 2500 MONITORING PRINL ABBREVIATIONS AL ALARM ACC ACCUMULATOR CK CHECK VALVE / COMPONENT CHECKING CR CONTROL ROOM H/L HIGH/ LOW PRESSURE INTERFACE HX HEAT EXCHANGER HPCI HIGH PRESSURE COOLANT INJECTION I CONTAINMENT PENETRATION IN FLOW TOWARD REACTOR IND INDEPENDENT OR INDICATION LO LOCKED OPEN LPCI LOW PRESSURE COOLANT INJECTION OUT FLOW AWAY FROM REACTOR MOV MOTOR OPERATED VALVE MV MANUAL VALVE MWT MEGAWATT (THERMAL)

NC NORMALLY CLOSED NSSS NUCLEAR STEAM SUPPLY SYSTEM P PUMP PIND POSITION INDICATOR PRESS PRESSURE PRINL PRESSURE INTERLOCK PSIG P0UNDS PER SQUARE INCH (GAGE)

RCS REACTOR COOLANT SYSTEM RPV REACTOR PRESSURE VESSEL SCS SHUTDOWN COOLING SYSTEM S&W STONE AND WEBSTER IN VS VALVES STR0KED FOR TESTING W WESTINGHOUSE

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APPENDIX B SURVEY OF LICENSEE'S RESPONSE TO SELECTED SAFETY ISSUES Plant Name and Unit Yankee Nuclear Power Station Item 03.02a. Steam Binding of Auxiliary Feedwater Pumps Is the discharge or the suction piping of the auxiliary feedwater pumps hot?

No. Verified by inspector on 5/9/85 Is the licensee monitoring and recording the temperature of the auxiliary feedwater system piping once per shift to detect back leakage? If not, how frequently?

No monitoring is being performe Is temperature readout local or in the control room?

There is neither local nor control room indication of temperatur What is the method of monitoring AFW piping temperature? (For example:

touching pipe, temperature sensing tape, or pyrometer.)

None performe . Is the licensee monitoring the temperature of the auxiliary feedwater system piping after each operation of a pump to detect back leakage?

N Did the licensee determine that procedural changes were needed to assure check valve seating when securing the auxiliary feedwater system?

None were determined necessar Have the changes been made?

None were determined necessar Have procedural guidance and training in identifying back leakage and returning the system to operability been provided?

No procedural guidance or training in identifying back leakage has been provided to the plant operators. Procedural guidance exists for returning the system to operability following routine testin k_ '

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Appendix B 2 Provide a brief summary description of procedural corrective actions (For example, vent and flush).

No procedural corrective actions have been implemente Is the licensee performing periodic leakage tests of the check valves (or' isolation valves if normally closed) in the auxiliary feedwater dis-charge line? How frequently?

Infrequentl Is the licensee performing periodic inspections of the check valves (or isolation valves if normally closed) in the auxiliary feedwater discharge line? How frequently?

Infrequentl . For any items which are not implemented, does the licensee have an alternate reason or justification?

Yes If so, provide a brief description:

Item The licensee indicates that operators check equipment in their watchstanding areas, and therefore, would detect backleakage from check valves. Additionally, they indicate that the number of check valves required to leak (at least two)

reduces the likelihood of this type of problem. The inspector found no evi-

'dence to substantiate the licensee's claim that operators check the piping for temperature to ascertain functioning of the check valve Item 4'.

The licensee maintains that based upon past experience and normal watchstand-ing practices no action is necessary. The inspector's interview of Operations Department Personnel, and procedural instructions review, do not support the licensee's justification that credits watchstanding practice Item The licensee has stated that sufficient differential pressure is developed to close the check valve Item The licensee has indicated that with backleakage not having been a problem at this plant, no actions on this item is necessary. Plant training cover good watchstanding practices and actions which should be taken in the event equip-ment or systems are not operating normally.

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Appendix B 3 Item The licensee indicates that flow paths are verified by procedure and therefore operation of the check valves is also verified.' Maintenance on the check valves is performed on an as needed basis. No PM program exists for the check valves. When the motor driven emergency feedwater pumps have maintenance per-formed, the applicable procedure requires an 1.'spection be performed on the

' discharge check valve of the pum I

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