IR 05000245/1987027

Insp Repts 50-245/87-27 & 50-336/87-23 on 870926-1026.No Violation Noted.Major Areas Inspected:Physical Security, Plant Operations,Surveillance & Maint Activities,Fuel Receipt & IE Bulletin 87-00l Followup

ML20237B071
Person / Time
Site:	Millstone
Issue date:	12/08/1987
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20237B002	List: IR 05000245/1987027 ML20237A999
References
50-245-87-27, 50-336-87-23, IEB-87-001, IEB-87-1, NUDOCS 8712160005
Download: ML20237B071 (17)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No: 87-27 and 87-23 Docket No: 50-245 and 50-336 License No: DPR-21 and DPR-65 Licensee: Northeast Nuclear Energy Company P.O. Box 270 Hartford, Connecticut 06101-0270 l

Facility: Millstone Nuclear Power Station, Waterford, Connecticut l Inspection at: Millstone Unit 1 & 2 Dates: September 26 - October 26, 1987 Inspectors: William J. Raymond, Senior Resident Inspector Peter Habighorst, Reactor Engineer Approved: M/m 6 In Ebe C. McCabe, Chief, Reactor / Projects Section 1B Date Inspection Summary: Inspection on September 26 - October 26, 1987 (Report No. 50-245/87-27 and 50-336/87-23)

Areas Inspected: Routine, unannounced inspection on day and back shifts  ;

by resident and region-based inspectors of: actions on previous inspection  !

findings; physical security; plant operations, including operational status  !

reviews and facility tours; bypass of non-essential diesel generator trips (RI TI 87-04); surveillance and maintenance activities; feedwater hydrogen injection testing; new fuel receipt and inspection activities; committee activities; and followup of IE Bulletin 87-01 and licensee event reports (LERs). The inspection involved 114 hour0.00132 days <br />0.0317 hours <br />1.884921e-4 weeks <br />4.3377e-5 months <br /> Results: No violations were identified. Routine reviews of plant activities

! identified no conditions adverse to safe plant operations. Licensee and resident inspector followup is warranted on the review of plant design changes to assure applicable technical specification and procedure changes have been completed (report detail 8.0).

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TABLE OF CONTENTS Persons Contacted...... ................... . . .. ..... 3 Summa ry o f Fac i l ity Acti v i ti e s . . . . . . . . . . . . . . . . . . . . . . ...... 3 Status of Previous Inspection Findings Electrical Work Controls................ . ..... ... 3 Commitment Completion Timeliness.. .................. 3 Observations of Physical Security.................... .... . 4 Facility Tours and Plant Operational Status Reviews Safety System Operability..................... .. . 5 Plant Incident Reports.... .... ........... ....... 5 l EOF Power Supply Event Classification.... .......... 7 l Unit 2 Tagging Operations.... .................. . . 7 Unit 1 Unidentified Leakage Inside the Drywell . . . . . 8 Bypass of Nt r ential Emergency Oiesel Trips (TI 87-04).. . 8 Unit 1 Surveillance and Maintenance......... ............... 9 ECCS Actuation Signa:s - Waiver of Compliance. ............. 10 Unit 2 Fuel Receipt and Inspection. ............... .... ... 12 10.0 Licensee Event Reports............... . ......... .......... 14 11.0 IE Bulletin 87-01..... .................... .. ...... ..... 15 12.0 Committee Activities..................... .. ............... 15 13.0 Unit 1 Feedwater Hydrogen Injec tion Test. . . . . . . . .... ...... 16 14.0 Emergency Preparedness Exercise..... .. .................... 17 15.0 Management Meetings... ........... ......................... 17

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DETAILS

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1.0 Persons Contacted Inspection findings were discussed periodically with the supervisory and management personnel identified belo Mr. R. Borchart, Reactor Engineer, Unit 2 Mr. J. Keenan, Superintendent, Unit 2 Mr. R. Palmieri, Operations Supervisor, Unit 1 Mr. S. Scace, Station Superintendent Mr. J. Stetz, Unit 1 Superintendent Ms. P. Weekly, Security Supervisor 2.0 Summary of Facility Activities i

Both Millstone Unit 1 and 2 continued routine full power operation j throughout the inspection period. The annual emergency preparedness exercise was conducted on October 8,1987, and involved a drill scenario '

on Unit .0 Status of Previous Inspection Findings (Closed) Inspection 50-336/86-23: Review of Administrative Controls for Electrical Work. By letter dated February 13, 1987, the I licensee was requested to respond to NRC concerns involving j electrical work practices that resulted in reactor trips and loss of I normal AC powe The licensee responded in a letter dated March 20, I 1987 to provide his assessment of the cause for each event addressed in the inspection report, and the corrective actions needed to prevent recurrence. The inspector reviewed the licensee's i corrective actions and concluded that they were appropriate and )

timel Specifically, the inspector verified that Revision 3 of i procedure 2720C6 dated 6/18/87 contained new instructions regarding installation of the potential transformer drawer that would assure proper alignment of the uni No inadequacies were identifie This response item is considered close .2 (Closed) Inspection 50-245/87-12: Submittal of Additional Infor-mation in Response to IE Bulletin 84-03 and Timely Completion of Commitments. NNECO submitted a supplemental response to IE Bulletin

! 84-03 by letter dated September 18, 1987. Based on a preliminary i review of the submittal, the inspector verified that the licensee addressed the issues listed as outstanding in his November 29, 1984 response to the bulletin. Further detailed review and evaluation of the licensee's supplemental response will be completed during a subsequent routine inspection. Completion of this IE Bulletin 84-03 effort is tracked by open Unresolved Item 50-245/87-12-0 i

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-4-The licensee also submitted a letter dated October 1, 1987 to address NRC staff concerns over.the timeliness of licensing submittals and commitment implementation. The licensee recently '{

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took additional actions to improve performance on commitment l implementation, as described in a letter dated June 25,.1987. The licensee's actions described in the June 25 letter were found acceptable by the staff, as discussed in the NRC letter dated August j 24, 198 In his October 1, 1987 letter, the licensee further j demonstrated his sensitivity to this issue and reaffirmed his J intention to improve performance. These actions were responsive to I the staff's concerns. The inspector will further evaluate the long {

term trend of the licensee's commitment completion performance i during subsequent routine inspection .0 Observations of Physical Security Selected aspects of site security were verified to be proper during tours, including site access controls, personnel and vehicle searches, ,

personnel monitoring, placement of physical barriers, compensatory j measures, guard force staffing, and response to alarms and degraded conditions. The inspector also reviewed security controls established for handling and storage of new fuel. Security guards were interviewed l and found knowledgeable of accountability and procedural requirement No inadequacies were identified. The following item warranted inspector j i followu '

Security event reports (SERs) issued during the inspection period were reviewed to verify 50.73 reporting requirements were met, and the report ,

accurately described the event The security reports reviewed included l SER 87-12 dated 9/25/87, SER 87-13 dated 9/25/87, and SER 87-14 dated !

9/25/87. The inspector noted that, in response to a previous NRC inspection finding (IR 245/87-22,336/87-20), the licensee began a security event log that was separate from the licensee event report log and started numbering security event reports consecutively beginning with SER 87-12. No inadequacies were identifie .0 Facility Tours and Plant Operational Status Reviews, Units 1 & 2 i

The inspector reviewed plant operations from the control room and I reviewed the operational status of plant safety systems to verify safe l operation of the plant in accordance with the requirements of the j technical specifications and plant operating procedures. Actions taken to -

meet technical specifications related to inoperable equipment were reviewed to verify the limiting c nditions for operations were me Plant logs and control room ind'. tors were reviewed to identify changes in plant operational status since the last review and to verify that changes in the status of plant equipment was properly communicated in the logs and record l

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Control room instruments were observed for correlation between channels, proper functioning and conformance with technical specifications. Alarm l conditions in effect were reviewed with control room operators to verify i proper response to off normal conditions and to verify operators were i knowledgeable of plant status. Control room manning and shift staffing were reviewed and compared to technical specification requirements. The inspector observed plant operations, maintenance and surveillance )

activities during regular and back shift hours to verify safe operating '

practices and that activities were conducted in accordance with approved procedures. The back shift inspections included tours made at 7:00 I on 10/16/87, and at 9:30 p.m. on 10/19/87. Posting and control of l Radiation Work Permit (RWP) 87-8817 was reviewed on October.15, 1987 and )

the use of personnel monitoring devices and compliance with the RWP l requirements were verifie Plant housekeeping controls were observed, j including the control of flammable and other hazardous material i Operators were found cognizant of control room indications and plant statu No inadequacies were identifie The following specific activities were also addressed:  !

5.1 Safety System Operability l Emergency systems were reviewed to verify they were operable in the standby mode. The systems reviewed included the following: Unit 1

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- the low pressure coolant injection, core spray, isolation con-denser, standby gas treatment system, hydraulic control units, and the standby gas turbine generator; Unit 2 - the safety injection tanks, low pressure safety injection, high pressure safety injection, containment spray, and emergency diesel generators. The review included proper positioning of major flow path valves; operable normal and emergency power supplies; indicators and controls functioning properly; and a visual inspection of major components for leakage, cooling water supply, lubrication, and  ;

general condition. References used included applicable flow dia-grams and Unit I surveillance procedure SP 623.18. No inadequacies were identifie .2 Plant Incident Reports i

The plant incident reports (PIRs) listed below were reviewed during the inspection period to: (i) determine the significance of the events; (ii) review the licensee's evaluation of the events; (iii)

verify the licensee's response and corrective actions were proper; and (iv) verify that the licensee reported thelevents in accordance i with applicable requirements. The PIRs reviewed were: Unit 2, 87-71 through 87-74; and Unit 1, 87-86 through 87-91, 87-93 and 87-0 PIR 1-87-91 concerned the completion of a design change

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-6-that removed the low pressure permissive from the low pressure ECCS pump actuation logic without obtaining a license amendment from the NR That matter is discussed further in Section 8.0 below.

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Otherwise, as for the examples noted below, no inadequacies were identified and the inspector had nr further comments.

l 5. PIR 2-87-71 Plant incident report 87-71 addressed a failed In-Service-Inspection (ISI) surveillance on check valves j (2-MS-4A and 2-MS-48) in the steam supply line for the 3 auxiliary feedwater pump turbine. The check vahes were determined not to fully seat under reverse steam flow conditions. AFW operability is not adversely affected by the >

check valve leakage. The licensee identified this condition by surveillance (ISI 21134-1A) on September 30, 1987. Since that date, the licensee has caution-tagged closed 2-MS-201, the #1 steam generator (SG-1) supply valve to the auxiliary feedwater pump turbine, to minimize check valve backflow leakage through 1 2-MG-4A. The SG-1 steam supply valve to the auxiliary turbine j was selected to be caution-tagged closed becausa a steam trap downstream of this valve removes moisture buiidup between the check valve and supply valve. The SG-2 steam supply valve does-not have a steam trap between the supply valve and check valv A trouble report to re-work or replace 2-MS-4A and 2-MS-4B awaits licensee engineering evaluatio '

5. PIR 1-87-86 This PIR concerned the September 23, 1987 dis-covery that the high radiation area access door on the 14 f elevation of the Reactor Building was closed but not locked as required. The gate is the access point to the Northwest corner room, which contains the Reactor Building Equipment Drain Tank, and which can have radiation dose rates in excess of 1000 mrem /h The gate was immediately locked upon discovery at 1:50 p.m. by a Health Physics Technicia The inspector reviewed the licensee's investigation and follow-up corrective actions with the Unit 1 Health Physics super-viso The licensee stated that radiation surveys in the corner room at the time of the discovery showed whole body dose rates were less that 1000 mrem /hr. Thus, the incident did not violate NRC regulations. The gate was in good mechanical condition and was most likely left open by the last plant worker who had access to the roo The individual responsible for the unlocked gate was not identified. Corrective action included discussing the incident with plant personnel and placing a chain and padlock on every high radiation area (HRA)

access door in the radiation controlled area. A purpose of the extra lock was to use a locking mechanism that would require a conscious effort to secure when leaving HRAs. The inspector

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-7-observed the additional locks installed on HRA entry ways during routine tours in the Reactor Building. The inspector I identified no instances in which the HRA doors were not I properly controlle .3 Event Classification-EOF Power Supply l

The inspector noted on October 19, 1987, that the normal power supply (27KV Flanders Line) to the Emergency Operations Facility (EOF) was lost for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> due to a problem offsite. The EOF diesel provides backup power for data and communication links upon loss of normal electrical power to the EOF. The diesel started on October 19, 1987 and supplied the EOF loads as required. The inspector noted that the Unit I duty shift supervisor evaluated the event as a non-emergenc i During routine weekly surveillance on September 18, 1987, the l EOF emergency diesel became inoperable when the engine cooling j water pump broke down. The diesel was repaired and returned to  !

service by September 19, 1987, as documented in Inspection Report 50-423/87-17. The Millstone Unit 2 Shift Supervisor classified the ,

incident as an Unusual Event based on the requirements of 10 CFR 1 50.72(b)(1)(v), major loss of emergency assessment capability for greater than one hou The licensee notified the NRC and state and local authorities. At that time no inadequacies were identified regarding the licensee's classification, which was considered  !

conservativ i During subsequent evaluation, the licensee concluded "at the EOF facility was operable at the time based on the avai'iability of the normal power supply (from the Flanders Line), and thus that no loss of assessment capability had occurred. The Unit 2 Engineering Support Supervisor stated that, in the future, based on the above reasoning, an emergency would not be declared in similar circumstance The inspector acknowledged the licentee position described above and identified no inadequacies based on review of 10 CFR 50.72 and 50.73 ,

reporting criteria. The inspector concluded that it would be overly conservative to require both the normal and backup EOF power sources to be operable to consider the EOF operational and that such a requirement is not presently contained in the facility licens The inspector had no further comments on this ite .4 Unit 2 Tagging Operations Safety tags on plant equipment were reviewed during plant tours to assure equipment and tagging were controlled in accordance with

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procedure OP 326 The following tagging order was reviewed: TO 1020-87, pressurizer relief valve blocking valve. Affected plant systems affected were reviewed to verify equipment availability was consistent with the plant status and operability requirement No inadequacies were identifie I 5.5 Unit 1 Unidentified Leakage Inside the Drywell

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The licensee noted that leakage collected by the drywell floor drain sump (DWFDS) increased above 1.0 gpm on October 14, 1987. The leak i rate remained greater than 1.0 but well below 2.5 gpm for the of the inspectio Plant operation is permitted by Technical Specification - 3.6.D. if unidentified leakage remains below 2.5 gpm. The inspector l noted that plant operators check the leak rate into the DWFDS at l least once per shift, and then plot and trend the leakage two times l per shift when it is in excess of 1.0 gpm. Plant operators trend sump leak rates using graphs maintained in the control room. The inspector reviewed the graphs of leak rate for the period from May, 1987 until the present and noted that leak rates were generally in the range from 0.5 gpm to 1.0 gpm. The leak rate for the present period remained at about 1.0 gpm with a very slight positive tren >

No inadequacies were identifie The DWFDS leak rate trend will be reviewed by the inspector during subsequent routine inspection '

6.0 Bypass of Non-Essential Emergency Diesel Trips (RI TI 87-04)

The inspector reviewed the diesel generator protective trip circuitry design, per Region I Temporary Instruction 87-04, to determine whether non-essential trips are bypassed for both a Loss of Coolant accident (LOCA) and a loss of normal power (LNP) transient. The references used included Unit 1 FSAR Section 8.3 and Unit 2 FSAR Section 8.3.3, along l with associated figures and drawings. The diesel design for both units l includes essential and non-essential protective trips. Only the ,

essential trips remain in effect for emergency operation since the l occurrence of the specific conditions could result in rapid degradation  !

and loss of the engine. The trips that are not bypassed are as follows: 1 Unit 1 Unit 2

+ engine overspeed + engine overspeed

+ low lube oil pressure + low lube oil pressure

+ generator differential current + generator differential current

+ voltage restraint overcurrent + voltage restraint overcurrent

+ engine start failure For Unit 1, the diesel will start on a loss of normal power (LNP) on the associated 4KV bus, or on an ESF actuation (accident) signal of high drywell pressure or low reactor vessel water leve In addition to the above essential trips, three additional trips (crankcase high pressure, l

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coolant high temperature and coolant low pressure) are provided when the engine runs in the non-emergency mode; i.e., for LNP conditions without a concurrent accident signal. Based on a review of the design drawings, the inspector noted that the three non-essential trips are not developed using coincidence logic for detection of the faulted conditio No design deficiencies were identified relative to the plant licensing basis, but a concern exists that the present design might allow the diesel to be rendered inoperable under LNP conditions due to the failure )

of a single non-safety-related trip devic The inspector noted, however, that no single failure could render both the Unit 1 diesel-generator and the independent gas turbine generator inoperable. Thus, emergency power from at least one source would be assured, and that is adequate to carry reactor safe shutdown load For Unit 2, the diesel automatically starts on a loss of power on its associated emergency bus, and there is no separate start signal on safety injection actuation (SIAS). Based on a review of the Unit 2 starting logic, the inspector verified that the non-essential trips are bypassed for any combination of conditions involving LNP, SIAS, or LNP with SIA No inadequacies were identifie The inspector had no further comments on this area at this tim However, this item will be reviewed further c.. a subsequent routine inspection of both Units 1 & 2 to verify surveillance test procedures adequately test the bypass functio .0 Unit 1 Surveillance and Maintenance During control room observations on September 30, 1987, with the plant ,

at 100% power and core flow, the inspector noted spurious rod blocks on l channel #7 of the Rod Block Monitor (RBM). Technical Specification 2. requires the Average Power Range Monitor (APRM) rod block trip setting to be at 100% power for the given plant conditions. Surveillance procedure SP-410C, Rod Block Monitcr Calibration / Functional Surveillance, step i 7.11.3 spacifies a rod block setpoint of 101.5% - 105% for 100% core flow and power. Thus, the rod blocks were conservative relative to required setpoints but indicated a potential problem with the RBM channel On October 1, the licensee used SP-410C (Rod Block Monitor Calibration /

Functional Surve,11ance) to. determine the cause for the spurious rod blocks. The objective of this procedure was to functionally test and calibrate the RBM and to satisfy the surveillance requirements 'of Technical Specification 4.2, Table 4. The inspector observed the troubleshooting activities completed using SP 410C and verified that the digital voltmeter and card extenders (G-1 &

G-2) met calibration requirements. Testing was performed by qualified

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personnel, and adherence to the written procedure was complet The troubleshooting effort did not identify the root cause of spurious rod blocks from channel #7 of the RBM. The licensee informed the inspector i that a work order would be issued and SP-410C would be performed again, j On October 2, the licensee generated work order M1-87-11770 to troubleshoot RBM-7 using spare modules from RBM-8, and to test RBM-7 using applicable portions of SP-401C. The completion of work order M1-87-11770 resulted in replacement of the RBM drive card. Upon completion of the drive card replacement, the licensee performed steps 7.5.3, 7.11.7, 7.11.8, 7.11.10, 7.11.11, and 7.11.3 of SP 410 Each of the steps performed in SP-410C verified local meter readings were within the tolerance listed, and all block functions operated at the required setpoint These actions verified that the rod blvck monitor was operating properl The inspector had no further questions on this matter.

l 8.0 ECCS Actuation Signals-Waiver of Compliance l

l The licensee notified the resident inspector and the NRR Project Manager ;

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at about 3:00 p.m. on October 16, 1987 of licensee failure to submit a 1 Technical Specification (TS) change request prior to modifying the low pressure Emergency Core Cooling System (ECCS) pump initiation logic via a design change during the 1987 refueling outage. The discrepancy was identified by site engineering personnel during a review of ACP-QA-9.02A, Surveillance Master Test Control List. This biannual review of sur- l veillance procedures was completed to assure the procedures accurately !

implemented the license requirements. The only discrepancy identified !

was the ECCS pump initiation setpoints described in TS Table 3. l Design change PDCR 1-23-86 was implemented as a result of recommendations I of the 1983 Reactor Protective System (RPS) Setpoint Drif t Evaluation (PA

"83-072). The initiation logic to start the Core Spray and Low Pressure Coolant Injection pumps was modified to delete the low reactor vessel pressure permissive portion of the (ECCS) start signal. That is, the original initiation logic started the ECCS pumps on high drywell pressure, or on low-low reactor vessel water level in conjunction with low reactor pressure. The modified initiation logic starts the low pressure ECCS pumps on either high drywell pressure or on low-low vessel water leve The proposed logic modifications were initiated by a design change in 1986. A pre-implementation PDCR design review in May 1986 failed to identify that the proposed logic changes would affect.the Protective Instrumentation Limiting Condition for Operation (LCO) and Surveillance requirements of TS Tables 3.2 and 4. Section 7.A of the PDCR package, involving review of the change for administrative impact, indicated that "no technical specification change was required" as a result of the modification, and NRC approval prior to declaring the

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modification operational was annotated "not applicable". This error occurred during the Northeast Utilities Service Company (NUSCO)

engineering review of the package. Subsequent review of the PDCR by other NUSCO personnel, plant personnel and the Plant Operations Review Committee (PORC) also failed to identify the initial erro Licensee and NRC staff review of this item on October 16, 1987 verified that plant operation in violation of this specific TS 3.2 LCO had no 1 adverse safety effec The original design basis for the low pressure permissive portion of the ECCS pump start signal stems from operational concerns and is not related to accident analysis provisions needed to mitigate any analyzed transients or accident The low pressure permissive was initially intended for larger BWRs (BWR-4,-5.-6 designs)

to avoid inadvertent ECCS starts during vessel level decrease trans-ients following reactor trips and loss of feedwater transient Operational experience has shown that this is not a problem at Millstone Eliminating the pressure permissive provides low pressure ECCS pump start and availability to the operator sooner following an acciden The proposed removal of the associated pressure switches was identified 1 to the NRC staff as Integrated Safety Assessment Program (ISAP) Topic I 3.3.69 (Draf t NUREG 1184, page 3-69) to allow ECCS pump start on either high drywell pressure or low-low water level . The NRC staff concurred on the scope of this topic by letter dated March 3, 1986. Additionally, the RPS Evaluation completed by the licensee in 1983 showed that as little as 20 psi drift in the pressure switch PS 263-54A&B setpoints used to derive the permissive signal could result in exceeding the 2200 degree F limit on I fuel clad temperatur Removing the permissive reduced reliance on {

components whose failure or malfunction could adversely affect mitigation )

of an accident. Thus, safety is enhanced by reducing the probability of malfunction of equipment important to safet The inspector reviewed PDCR 1-23-86 and post-installation testing j completed per procedures SP 412J, Core Spray System Automatic Actuation, 1 Revision 7, completed 8/8/87, and SP412K, Low Pressure Coolant Injection (LPCI)/ Containment Cooling Logic Test, Revision 4, completed 8/11/8 The following Control Wiring Drawings (CWDs) were also reviewed:

740, 741, 751, 752, 759, 760, 761, 762, 784, 785, 786 and 787. The design change resulted in the removal of pressure switches PS 263-54A&B and appropriate rewiring of the associated ECCS cabinets. The inspector's review verified that the present as-built actuation wiring will provide for ECCS pump start on either high dryweil pressure or low-low vessel water level. Post-implementation testing for the PDCR modifications verified proper operation of the starting logic. No l inadequacies were identifie l The inspector reviewed the licensee's followup actions subsequent to the initial discovery on October 16, 1987 and identified no inadequacie The inspector attended the October 19, 1987 joint Nuclear Review Board (NRB) (#87-14) and PORC (#1-87-138) meeting which discussed the safety evaluation and recommended approval of the proposed change to TS .

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(PTSCR 1-21-87). The inspector verified that the ECCS initiation logic still uses a low reactor vessel pressure permissive to open the Core Spray (CS) & LPCI system isolation valves, which inhibits low pressure injection until reactor pressure reaches 350 psig and preserves the protection for low pressure piping. Minimum flow lines protect the pumps during operation while isolated from the reacto Plant emergency procedures instruct the operator to isolate the low pressure pumps following an accident if they are not needed. No inadequacies were identifie Based on the above the NRC staff concluded that plant operation should be allowed to continue, but that the licensee should expeditiously seek a

, change to the Technical Specifications to remove the reactor vessel low -

I pressure signal. Changing the ECCS actuation logic without a TS amend-ment is contrary to the Technical Specifications and 10 CFR 50.59. While a safety enhancement is indicated for this specific change, the failure l to obtain a TS change indicates inadequate processing of design changes in regard to revising Technical Specification The licensee committed to complete, by November 1987, a review of all plant design changes completed during the 1987 refueling. outage, to assure that all appro-priate changes to plant procedures and the technical specifications were completed. Enforcement action is unresolved pending licensee completion and NRC review of this aspect (50-245/87-27-01).

t NRR and Region I management review determined that a Waiver of Compliance j j

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from the TS 3.2 LCO would be appropriate pending receipt of the licensee j amendment from NR Licensee management committed, during a telephone !

conference at 5:50 p.m. on October 16, 1987, to submit the requested information and proposed change. The licensee requested a temporary waiver of compliance from TS 3.2 requirements by letter dated October 19, ;

1987, and stated the intention to submit a license amendment request !

pursuant to 10 CFR 50.91. The amendment request was submitted on October 20, 1987. By letter dated October 21, 1987, the NRC issued a temporary waiver of compliance from TS Tables 3.2.2 and 4.2.1 until December 21, 1987 while the staff completes the processing of the requested license amendment. The inspector had no further comment on this aspec .0 Unit 2 Fuel Receipt and Inspection

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The inspector reviewed the following procedures concerning fuel handling inspection receipt effort for Unit 2:

OP-2303, Rev. 16, Fuel Handling System OP-2210A, Rev. 7, New Fuel Assembly and CEA Receipt and Inspection OPS Form 2303-1, Refueling Machine Preoperational Checklist L

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OPS Form 2210A-1, Fuel Receipt / Inspection Shipping Vehicle Work Order M2 87-09961, Load test on Auxiliary Building Cask Crane, Auxiliary Hook and Main Hook Work Order M2 87-09960, Load test on short fuel handling tool Work Order M2 87-09959, Load test on slings and cables for new fuel receipt and inspection The inspector interviewed licensee personnel concerning fuel / control element assembly (CEA) inspector qualifications. Each of the prospective inspectors were trained on precautions and procedural steps of OP-2210A, New Fuel Assembly and CEA Receipt and Inspectio In the training session, prospective inspectors were presented with photographs displaying past fuel receipts and inspections, and a question and answer period was i conducted at the conclusion of the sessio Prior to the unloading of the shipping containers, the inspector reviewed the following items on form OP 2210A-1:

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Container Stack heigh Swing bolts are intac Tie-down cables and chains are secured and no gross shifting has occurred in transien Inspection of the shipping container for gross external shipping damag The inspection performed by the licensee's reactor engineer was concise and performed in an expedient manne The inspector reviewed radiation work permit (RWP) 02453, (Description of work in Auxiliary Building at elevation 38'6") for radiological controls and descriptive information in regard to fuel inspectio The inspector had no further questions in regard to this are The inspector followed movement and licensee inspection of three fuel bundles (L52, L53, and L45) from their prospective shipping containers to the New Fuel Inspection Machine (NFIM). The inspector observed the licensee's reactor engineers perform steps 5.4.1-5.4.14 of OP-2210A detailing inspection of new fuel bundles. The three fuel bundles (L52, L53, and L45), met the requirements of OP-2210A. After the licensee's inspection, adequate protection was provided ta maintain the fuel in a clean condition in readiness for use statu Each operation was completed consistent with approved procedure The inspector had no further questions in this are .

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y 10.0 Licensee Event Reports '

Licensee Event Reports (LERs) submitted during the report period were reviewed to assess accuracy, the adequacy of corrective actions, compliance with 10 CFR 50.73 reporting requirements, and to determine if j there were generic implications or if further information was required, i Selected corrective actions were reviewed for implementation and {

thoroughness as documented belo The LERs reviewed wer Unit 1 )

+ 86-06-02, Failure of 1-MS-1D and 1-MS-2 + 86-18-01, Reactor Protection System Initiation from IRM Noise Spik + 87-12-01, Diesel Generator Ceiling Fire Coating Degradatio + 87-15-01, Local Leak Rate Test Failure + 87-36, Reactor scram on 8/26/87 during APRM Surveillanc + 87-37, Missed Surveillance, Manual Reactor Scram Functio + 87-38, Reactor Scram (9/3/87) on Low Air Header Pressur + 87-39, APR/LP Core Cooling Pump Interlock Overdue Surveillanc + 87-40, Failure to Meet Acceptarce Criteria of SP 408 NRC review of the licensee's followup and corrective actions for the reactor scram on 9/3/87, LER 87-38, is documented in Inspection Report 50-245/87-2 LER 87-40 concerned the failure of all four condenser low vacuum pressure switches, PS-503A to 0, to meet the acceptance criteria specified in a routine surveillance test conducted on September 15, 1987. The four ,

Barksdale Model DIT-HI8SS pressure switches had a measured trip setting )

of 21.2, 21.15, 20.85, and 20.95 inches of Hg vacuum, respectively, which )

did not meet the TS 3.1 acceptance criterion of greater than or equal to '

23 inches of Hg, decreasing. The licensee reported that the pressure switches had been installed as new equipment during the 1987 refueling outage because the previous switches were reaching the end of their established service life. The new switches were recalibrates and returned to service. The licensee concluded that the setpoint deviation was due to drift that occurs as new switches enter the initial operating perio The licensee increased the frequency of testing the switches from monthly to weekly until the switches have a demonstrated consistent reliabilit The inspector noted, based on review of the surveillance test results completed since September, that there have been no further i problems meeting the surveillance test acceptance criteria, and that the .

instrument setpoints seem to have stabilized within an acceptable range I around the required value, j The licensee reported this item under 10 CFR 50.73(a)(2)(i) as a violation of TS 3.1 requirements to meet the minimum number of operable instrument channels per trip system. The licensee's analysis of the event concluded that the faulty trip settings had no safety consequence L

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since the condenser low vacuum trip is provided as a back-up scram to the turbine stop valve closure scram. The inspector reviewed the technical specifications and the licensee's Unit 1 Reactor Protection System Setpoint Drif t Eva',uation Report, NE-83-R-424. This review confirmed that the low condenser vacuum scram is not relied upon to prevent exceeding a fuel clad safety limit. The turbine stop valve closure scram l alone is sufficient to assure the safety limit is met, and this scram is derived from a different set of pressure switches with a trip setpoint of 22.5 inches of Hg. Based on the above, the inspector concluded that the

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event described by LER 87-40 had little safety significanc Failure to meet a TS LCO is considered for enforcement action by the NR No notice of violation will be issued in this case since this item meets criteria in 10 CFR 2, Appendix C by being an issue of minor safety significance, identified by the licensee, reported as required, and for which corrective actions were timely and appropriate. The item would not i have been prevented by the corrective action on a prior violation. The '

inspector had no further comment on this ite .0 IE Bulletin 87-01 The inspector reviewed licensee actions in response to IE Bulletin 87-01, issued by the NRC on July 9,1987, to verify: (i) the bulletin was !

received by the licensee management and reviewed for applicability; (ii) '

the licensee responses were timely and met the bulletin requirements; and, (iii) licensee actions taken or planned were appropriat The licensee's responses to address NRC concerns regarding thinning of carbon steel piping in nuclear power plant balance of plant systems important to reactor safety were provided in a letter dated September 11, ,

1987. The licensee's submittal for Millstone Units 1&2 was responsive to I the NRC request.

l No inadequacies were identifie .0 Committee Activities The inspector attended meeting 87-41 of the Site Operations Review l Committee (SORC) on October 21, 1987. TS 6.5.2.2 requirements for a committee composition and quorum were met. The meeting agenda included review of revisions to various procedures and forms. The inspector observed a probing and questioning attitude by the SORC in regard to the matters under review. The inspector also attended Unit 1 PORC Meeting 1-87-138 on October 19, 1987, as described in Detail 8.0 above. No inadequacies were identified.

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13.0 Unit 1 Feedwater Hydrogen Injection Test The licensee performed a hydrogen injection test on Millstone Unit 1 during the swing and midnight shifts on October 17-19, 1987 to determine )

the feasibility of using hydrogen to control oxygen levels in the reactor coolant system during routine operations. The test was performed by adding hydrogen t, the feedwater stream on the suction side of the 1 condensate booster pumps in steps to achieve injection rates over the ]

range of 3 cfm to 52 cfm, while radiation levels, hydrogen and oxygen levels and the electrochemical potential of the reactor coolant were measure The testing was completed in accordance with Special Procedure 87-1-37, Hydrogen Water Chemistry Pilot Test, which was approved by the PORC in {

meeting 1-87-132. The inspector reviewed the test procedure and the j associated safety evaluad on to verify that the test would'not create an )

unreviewed safety question. The inspector noted that a license amendment J l was required to conduct the test, due to the increased radiation levels I

, anticipated as a result of increased concentrations of Nitrogen-16 (N-16)

I that would be released from the reactor, and that there would be a j corresponding increase in main steam line radiation. The licensee j received NRC approval (License DPR-21 Amendment #12 dated 9/29/87) to temporarily increase the setpoints specified in Technical Specifications i 3.1.1 and 3.2.E.3.c for the main steam line and steam tunnel ventilation l radiation monitors. The inspector verified that changes to the main i steam line and steam tunnel ventilation trip setpoints were made per the l requirements of the amendment. The inspector reviewed the test plan and equipment with licer.see personnel and verified that controls to safely use hydrogen onsite were implemented as required by the procedure, and that measures and controls assumed in the safety evaluation were in i place. The inspector also observed the testing in progress and verified that test activities were conducted per the procedures. No inadequacies were identified.

l Radiation levels in the plant and at the site baundary were monitored as the concentration of hydrogen injected into the feedwater was increase The licensee's initial estimate was that radiation dose rates around the l turbine during the test would increase by a factor of 1.5 to 8 due to the i increase in N-16 concentrations in the main steam. The inspector verified that, assuming radiation levcis increased 8 times, the estimated dose rate at the closest point on the site boundary (Niantic Bay) would 1 increase from the normal value to about 0.1 mrem /hr, and thus would not j create a significant concern. The actual dose rates measured during the test were greater than predicted at the maximum hydrogen injection rate, with results in points of major interest as follows: Unit 1 Intake - to 1.0 mrem /hr; Unit 2 Engineering Office - 0.65 mrem /hr; and Unit 1 & 2 i

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-17-s office corridor - I to 2 mrem /h The inspector noted that the nominal hydrogen injection rate needed to achieve the optimum electrochemical potential in the primary coolant was considerably less than the maximum value used during the test. The test was successful in identifying plant j areas for which additional shielding would be required if the licensee i decides to use feedwater hydrogen injection as a method to enhance BWR l corrosion control. No inadequacies were identifie .0 Emergency Preparedness Exercise '

The inspector participated in NRC observation team of an emergency plan exercise completed on October 8, 1987. In general, plar.t personnel

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performed well. Several improvement items were noted by licensee and NRC  !

evaluation personnel. The full results of the inspection are summarized  !

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in combined Inspection Report 50-245/87-26; 50-336/87-22; and SL 4.23/87-2 .

15.0 Management Meetings

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Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findirgs was also discussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspection. No written ,

I material relating to inspection findings was provided to the licensee during the inspectio i

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