IR 05000245/1987033
| ML20149J082 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 02/11/1988 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20149J052 | List: |
| References | |
| 50-245-87-33, 50-336-87-29, IEB-87-002, IEB-87-2, NUDOCS 8802220266 | |
| Download: ML20149J082 (29) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report: 87-33 (Millstone 1) and 87-29 (Millstone 2)
Docket Nos: 50-245 and 50-336 License Nos: DPR-21 and DPR-65 Licensee: Northeast Nuclear Energy Company P.O. Box 270 Hartford, Connecticut 06101-0270 Facility: Millstone Nuclear Power Station, Waterford, Connecticut .
Inspection at: Millstone Units 1 & 2 Dates: December 1-31, 1987 i
! Inspectors: William J. Raymond, Senior Resident Inspector 1 Lynn Kolonauski, Resider.t Inspector Peter Habighorst, Reactor Engineer Eben Conner, Project Engineer NRR Personnel: David Jaffe, Millstone 2 Project Manager Reporting Inspector: William J. Raymond Approved by: SYeOd HR OEd*, ) A 2 / 88 IB8 E. C. McCabe, Chief, Reactor Projects Section IB Date Summary: Report 50-245/87-33; 50-336/87-29 (December 1-31, 1987)
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Areas Inspected: Action or m evious inspection findings, physical security; plant '
operations, including operational status reviews and facility tours; implementation of itcense amendments, IE Bulletin 87-02 - Fastener Testing, surveillance testing, Scram Discharge Volume modifications, committee activities, and licensee event reports (LERs) [159 inspection hours]. ,
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Results: Inspection identified no unsafe plant operations. One Unit 1 violation i was identified for failure to report APR valve discrepancies identified during ,
surveillance testing in November 1985 (Section 3.0). One Unit 2 violation was '
- identified for failure to control overtime during the steam generator tube repair outage in January-February, 1987 (Section 7.5).
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TABLE OF CONTENTS PAGE Persons Contacted.................................................... 1 Summary of Facility Activities..... ................................. 1 Licensee's Action on Previously Identi fied Items. . . . . . . . . . . . . . . . . . . . . 1 3.1 VIO 50-245/87-21-01, Instrumentation and Control Surveillance .2 PEF 50-245/87-09-01, Reportability of Automatic Pressure Relief (APR) Check Valve Leak Test Results........ 2 3.3 PEF 50-245/87-09-02, Corrective Measures to Preclude APR Check Valve Leakage.............................. 4 3.4 PEF 50-245/87-09-06, Adequacy of Test Procedures....... ........ 4 3.5 UNR 50-336/87-25-05, Evaluation of control Room Radiation levels for Postulated Accident Scenarios.......... 5 Physical Security.................................................... 6 Facility Tours and Plant Operational Status Reviews - Units 1 and .1 Safety System Operability.................... .................. 7 5.2 Plant Incident Reports.......................................... 7 Isolation Condenser Valve IC-2 Inoperability - Unit 1........... 8 Surveillance - Unit 1..................................... .......... 9 Safety Issues Man.sgement System (SIMS) Items......................... 9 IE Bulletin 87-02, Fastener Testing to Determine Conformance with Applicable Material Specifications - TI 2500/2 ................... 14 TI 2515/90, Scram Discharge Volume Modifications..................... 15
1 Preparations for Refueling - Unit 2..... ...... .............. .... 21 1 Licensee Event Report - Unit 1, 50-245/87-42: Failure to Establish a Post Accident Sampling System (PASS) Surveillance. . . . . ............. 22 12. On-site Plant Operations Review Committee (PORC).. ................ . 23 1 Management Meetings. ................................................ 23 i
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DETAILS -l 1.0 Persons Contacted l
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Mr. S. Scace, Station Superintendent !
Mr. J. Stetz, Superintendent, Unit 1
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l Mr. J. Keenan, Superintendent, Unit 2 Mr. F. Dacimo, Engineering Supervisor, Unit 2 ;
Mr. B. Duffy, Engineer, Unit 2 :
Mr. J. Criscione, Staff Engineer, Unit 2 The inspector also contacted other licensee employees including members of the Operations, Radiation Protection, Chemistry, Instrumentation and Control, Maintenance, Engineering, and Security Department .0 Summary of Facility Activities Millstone 1. operated at full power except for normal power reductions for routine surveillance and corrective maintenance. The corrective maintenance activities requiring power reductions were the repair of the uncoupled "A"
. Feedwater Regulating Valve on December 15, rebrushing of the "B" Recirculation Pump motor generator set on December 21, and plugging of Main Condenser tubes on December 21 and 3 Millstone 2 was operating at 100% power on December 1, 1987. End of cycle coastdown operation began on December 6, 1987. A scheduled 59-day refueling and maintenance outage started on December 30, 1987. Major outage activities include reactor refueling; steam generator tube inspection and repair, and the pulling of one steam generator tube; replacement of the "0" reactor cool-ant pump motor, modifications for 10 CFR 50 Appendix R requirements, modifi-cations for control room human factors engineering, installation of a halon system in the DC Switchgear Room, replacement / repair of piping in the service water system and the main steam extraction system, and modification of the t controls circuit for four containment hydrogen purge valve .0 Status of Previous Inspection Findings 3.1 (Closed) VIO 50-245/87-21-01: Review of administrative controls for sur-veillances performed by the Instrumentation and Controls Department (I&C).
By letter dated September 24, 1987, the NRC requested the licensee to respond to two separate violations of Technical Specification 6.8.1.c, which requires that written procedures covering safety-related equipment be implemented. The first instance occurred on August 12, 1987 with the reactor in cold shutdown. An I&C technician misconnected test equipment during a test of the automatic blowdown logic. Because the I&C techni-cian assisting in the surveillance test did not independently verify the test equipment connection as required by the surveillance procedure, the mistake was not recognized until it resulted in a Low Pressure Coolant Injection (LPCI) system discharge of approximately 10,000 gpm to the reactor vessel. The second instance occurred on August 13, 1987 during
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a test of the Main Steam Line Isolation Valve (MSIV) closure logic. The failure of the I&C technicians to establish the required initial condi-tions resulted in a full Reactor Protection scram signal. No rod motion occurred because-the reactor was in a cold shutdown conditio By letter. dated October 23, 1987, the licensee reported that the primary cause for the events was personnel error due to inattention to detai Corrective actions to increase awareness and emphasize the importance of accurate procedure usage included the coverage of less frequently performed surveillances in on-the-job training and the expansion of significant events training to address personnel errors. Also, the test devices for Automatic Pressure Relief, Core Spray, and LPCI were color-coded to ensure positive differentiation and reduce the likelihood of misconnecting test devices. The inspector reviewed the licensee's cor -
I rective actions, observed their implementation, and found them to be appropriate and timely. No inadequacies were identifie Related items will be reviewed during future routine inspections.
l 3.2 (Closed) Potential Enforcement Finding 50-245/87-09-01: Reportability
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of Automatic Pressure Relief (APR) Check Valve Leak Test Results. The licensee responded voluntarily to this issue by letter dated November 20, 1987. The licensee provided additional information on the results
, of the APR leak rate test conducted on November 2, 1987. This assessment l showed that operability of the APR function was maintained even though l 8 of 12 check valves in the nitrogen supply failed to pass the required l 1eak rate test. After considering this information, the inspector de-termined that a 50.72(b)(2)(iii) report should have been submitted to the NRC because the information available at the +ime of failure of the surveillance test was not sufficient to determine that the APR function was operable. Therefore, to the best of the licensee's knowledge at the time of the occu rence, the failure represented a condition which alone could have prevented fulfillment of the APR functio Inspection Item PEF 87-09-01 is closed for tracking purposes and a new inspection item (amplified below) is opened for the violation issued with this repor The inspector reviewed the licensee's response, the design basis for the APR system and NRC guidance on meeting the 10 CFR 50 reporting criteria in NUREG 1022, inclusive of Supplement 1. The inspector noted that there are six main steam safety / relief valves (SRVs) for Millstone Four of these are used in the APR syste Because the valves are dual purpose and self-actuating without reliance on the nitrogen supply system for the reactor vessel pressure relief function, inoperability of the nitro-gen supply check valves would not degrade reactor coolant pressure bound-ary 'verpressure protectio The licensee stated in his response that the failure of the nitrogen supply check valves alone did not degrade nitrogen supply to the SRVs (since the nitrogen supply header was always intact), and therefore the SRVs would have been capable of performing their intended function. The licensee stated further that: (1) the nitrogen supply lines were not j
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seismically qualified prior to the 1987 refueling outage, and (11) an engineering review completed in response to IR 87-09 concluded that two fully operable SRVs, in conjunction with other ESF systems, would have been adequate to safely shutdown the plant even with an assumed loss of normal power and a single active failure. The licensee stated during i meetings with the inspector that reportability under 50.72(b)(2)(iii) I is predicated on multiple failures, namely, the occurrence of a design basis earthquake, the failure of the feedwater injection system, and a failure of the nitrogen supply header that would render four of the six SRVs inoperabl The inspector noted that the design basis for the engineering safety i systems, including automatic depressurization provided by four SRVs, is to mitigate the consequences of the spectrum of LOCAs assuming a concur-rent loss of normal power and seismic loadings assumed for the facilit Any system not "seismically qualified" is not credited for accident mitigatio It was because the nitrogen supply system to the SRVs was not seismically qualified (before 1987), and in response to the issues raised in IE Bulletin 80-01, that the licensee upgraded th9 check valves in the SRV nitrogen supply header. For the condition of the plant in 1985, no credit can be taken for makeup from the nitrogen supply header and proper operation of the APR header check valves is required to assume success of the APR function for the design basis even The inspector noted that 10 CFR 50.73(a)(2)(v) is the LER reporting cri-teria comparable to 10 CFR 50.72(b)(2)(111). NUREG 1022 and its associ-ated Supplement I state that the NRC desires the licensee to report events wherein a single safety system could have failed to perform its intended safety function under accident conditions, and regardless of whether or not an alternate safety system could have been used to perform the safety function. While the regulations do not require the reporting of single component failures if redundant equipment in the same system is operable to perform the safety function, this does not apply in this case since multiple SRVs were inoperable due to a common mode failure of the otherwise independent nitrogen supply system (i.e., header plus redundant check valves) for each safety / relief valv Based on the above, the inspector concluded that, for the conditions known in November 1985, and absent the subsequent conclusion that the safety function is assured by only two valves, the licensee should have submitted a report pursuant to 10 CFR 50.72 & 50.73 for the inoperable APR function when the surveillance test showed several SRVs were inoper-able. Failure to make the required report violates 10 CFR 50.72 (b)(2)(iii) (VIO 50-245/87-33-01). This item is addressed further in Inspection Report 87-12, which documents NRC review of licensee correc-tive actions as of August 10, 1987, including actions to upgrade the seismic capability of the APR headers. The inspector verified, based on a review of completed surveillance forms 1091-1 dated July 22, 1987, that all APR check valves were satisfactorily tested during the 1987 refueling outage. Based on the above, the inspector had no further
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questions regarding licensee actions to address operability of the APR check valves. Based on the information provided by the licensee's Novem-ber 20, 1987 letter, no further action is required regarding the licensee assessment of the even However, based on discussions with site man-agement and'a review of the NRC position for shis issue, no licensee consensus exists regarding reportability. Therefore, a response from the licensee is warrante .3 (Closed) Potential Enforcement Finding 50-245/87-09-02: Corrective Meas-ures to Preclude APR Check Valve Leakage. This item questioned whether the licensee had taken sufficient action to prevent recurrence of APR check valve failures identified during surveillance testing of the check valves in November 198 The licensee responded voluntarily to this issue by letter dated November 20, 1987. Inspector review of the licensee's response and corrective actions noted that actions were taken to identify and correct the root cause of the November 1985 test failure. The licensee determined that the initial test method, which involved blowing air from the header through the check valves prior to the leak rate test, was the most prob-able cause of the check valve leakage. The test procedure was subse-quently revised to bleed the header down through another vent. The ade-quacy of the corrective action was confirmed during the 1987 refueling j outage when retest of the APR valves showed that all check valves met
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tha leak test criteri Based on the above, licensee corrective actions were effectiv This item is close .4 (Closed) Potential Enforcement Finding 50-245/87-09-06: Adequacy of Test Procedures. The licensee responded voluntarily to this item by letter dated November 20, 1987, providing additional information regarding the surveillance procedures for the Low Pressure Coolant Injection (LPCI)
and shutdown cooling pump check valve Inspector review of the licensee's response and Section XI of the ASME Code Article IWV-3522 determined that testing the pump discharge check valve in the reverse flow direction is not required by the Code or NRC regulations. Changes to incorporate such testing in the SP 622.7 sur-veillance procedure would enhance the program and be in accorcl with good engineering practic However, the existing surveillance meets NRC re-quirement On the finding relative to procedures SP623.20 and SP1060-38 regarding testing of the shutdown cooling system check valves, the licensee agreed that the test procedure was deficient in that it failed to test pump discharge test valves 1-SD-3A and 1-SD-3B as required by the inservice test progra The deficiency was caused by administrative oversight in the procedure review and approval process: the requirement to test the valves was deleted from SP 623.20 but not added to SP 1060-38 as in-
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tended. The licensee noted that the intent of the surveillance require-ment was met in that both check valves were tested in spite of the in-adequacy. The licensee added requirements to test the check valves to procedure SP 1060A and verified the operability of the valves based on testing on July 27, 1987 during the refueling outage. As additional measures to prevent recurrence, the licensee. stated in his November 20
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response that all check valve surveillances will be reviewed.for adequacy to assure that the intent of the ASME Section XI Code is met. Completion of that action will be followed by the inspector and is considered a part of the unresolved item listed belo The failure to meet the Section XI requirements for the shutdown cooling-system check valves for testing conducted from September 1986 until April 1987 when the discrepancy was noted by NRC inspection is contrary to regulatory requirements. However, no violation will be issued because the program inadequacy was evaluated as an isolated case lacking safety significance. PEF 87-09-06 is therefore close However, the inspector noted that several other questions were raised during the 87-09 inspection regarding conformance of the licensee's pro-gram with Section XI. This concern is tracked as unresolved item 50-245/87-12-05. . The inspector will review the licensee actions to assure check valve surveillance testing meetsSection XI as part of the NRC followup to item 87-12-0 .5 (0 pen) Unresolved Item 50-336/87-25-05: Evaluation of Control Room Radiation Levels for Postulated Accident Scenarios. The licensee evalu-ated control room habitability based on the October 30, 1987 introduction of airborne radiation (causing 30*4 of the maximum concentration permis-sible for 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> per week exposure) into the control room via the ven-tilation system. The evaluation assessed the significance of the leakage path and evaluated the integrity of the control room envelope for com-parison with the assumptions postulated for design basis accident condi-
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Loss of Coolant Accident (LOCA) on Units 2 or 3 with a concurrent main steam line event on Unit 1; a rupture of a waste gas decay tank in the Unit 2 Protected Area BCJndary (PAB); and plant operation for one hour with the maximum allowable identified leak rate of 10 gpm concurrent with primary coolant radiochemistry at the maximum concentration allowed by the Technical Specification The engineering evaluation was documented in a calculation and memorandum from D. W. Miller to B. J. Duffy dated December 10, 1987, and was based on TACT computer run numbers 6282 and 6371. The licensee concluded that the dose rates from the Reactor Coolant System (RCS) leak rate scenario would be less limiting and would be bounded by the results of the LOCA scenario. The waste gas decay tank results would also be bounded by the LOCA result FSAR Tables 14.20-3 through 14.20-6 present the LOCA analysis results for the doses to the control room operators and show a limiting dose of 929 millirem whole body for a LOCA at Millstone For an RCS leak duration of one hour prior to isolation, the licensee
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6 calculated, for the subsequent 24-hour expos'ure, that the~ integrated whole body and thyroid dose to the control- room operators would be 110 millirem and 6.09 rem, respectivel These results are well.within the design basis limits-and represent consequences which are bounded by accidents previously analyzed and accepte The inspector noted that the licensee intends to test the control room envelope in the as-found condition to demonstrate that the 100 cfm in-leakage assumed in the accident analysis is bounding. The inspector will-follow the results of the control room envelope test. The inspector noted further that the licensee will address repairs to the control room and auxiliary building supply ventilation system via Engineering Unsat 3615. The long term fix for gas transport via-the floor drain system from the auxiliary building will be addressed via Engineering Unsat 361 No inadequacies wera identified with the licensee's actions or plan This item will be reviewed further on a subsequent routine inspectio .0 Observations of Physical Security Selected aspects of site security were verified for proper implementation during inspector tours. These included site access controls, personnel and vehicle searches, personnel monitoring, placement of physical barriers, com-pensatory measures, and guard force response to alarms and degraded condition No inadequacies were identified. The following event warranted further in-spector follow-u On December 22, two individuals under contract for NNECO entered a vital area (VA). They were authorized unescorted access to the Protected Area (PA) but were not authorized access to VAs. As the contractors attempted to open the VA door, an authorized worker was leaving the VA. The contractors apparently assumed that they had been granted access in view of the open VA door. Both contractors had been on site at en earlier date and were authorized unescorted access to this particular VA at that earlier tim This event occurred upon their return and on their first day on site under their current contrac A roving security guard responded to the automatic alarm caused by their in-trusion and removed the individuals from the VA within one minute of their entranc Both contractors maintained that they had received green "access permitted" lights upon using the card reader. When attempted by the security guard after their removal from the VA, their cards received red "access not permitted" light The contractors were reprimanded and retrained. The licensee sub-mitted a one-hour report to the NRC Operations Center in accordance with 10 CFR 73.71.c. The iospector noted no inadequacies in the licensee's response to the even .0 Facility Tours and plant Operational Status Reviews Control Room instruments were observed for correlation batween channels, pro-per functioning, and conformance with Technical Specifications (TS). Alarm conditions in effect and alarms received in the Control Room were reviewed
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and discussed with operators. Operator awareness and response to these con-ditions were reviewed. Operators were found cognizant of indications and plant conditions. Control room and shift manning were compared with TS re-quirements. Posting and control of radiation, contaminated, and high radi-l ation areas were inspected. Use of and compliance with Radiation Wcrk Permits and use of required personnel monitoring devices were checked. Plant house-keeping controls were observed, including control of flammable and other hazardous materials. Logs and records were reviewed for compliance with station procedures, to determine if entries were correctly made, and to verify- *
correct communication of equipment statu These records included various <
operating logs, turnover sheets, tagout and jumper logs, and Plant Information Report Inspections of the control room were performed on weekends and back-shifts on December 27 at 2:00 pm and December 30 at 6:00 pm. Operators'and shift personnel were found to be alert and attentive to their duties, and responded appropriately to annunciators and plant conditions. No inadequacies were identified. -The following specific activities were also addressed-
l 5.1 Safety System Operability Review !
Standby emergency systems were reviewed to determine system operability !
and readiness for autonatic initiation. The following systems were in- !
cluded in the review: Unit 1 - low pressure coolant injection, core spray, standby gas treatment, isolation condenser, and control rod drive hy-draulic control; Unit 2 - containment spray, safety injection tanks, low pressure safety injection, high pressure safety injection, and emergency diesel generators. The inspector also reviewed the following documenta- ,
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tion for the Unit 2 auxiliary feedwater system: SP-2610C, auxiliary feed-
- water system lineup and operability; FSAR Section 7.3; OP-2322, Auxiliary !
Feedwater System; Technical Specification 3.7.1.2, 3.7.1.3, 4.7.1.2. :
and 6; and P&ID 26002/26005. For the Unit 2 auxiliary feedwater system, !
the inspector walked down the system piping components and control in '
the feedwater pump room, the turbine building and the control roo ,
The review censidered: proper positioning of major flow path valves, E operable normal and emergency power supplies, proper operation of indi-cators and controls, visual inspection of accessible major components for leakage, cooling water supplies, lubrication and other general con-dition References used for the review included applicable flow dia- !
grams and operating procedures. No inadequacies were identifie l During the walkdown of the Unit 2 AFW system, the inspector noted several i minor housekeeping deficiencies. These were identified to the license The inspector will follow-up licensee actions on these items. No other discrepancies were identifie ;
5.2 Review of Plant Incident Reports Unit 1 Plant Incident Reports (PIRs) 101 - 103 were reviewed to (1) de-termine the significance of the events; (ii) review the licensee's evaluation of the events; (iii) review the licensee's response and cor- .
rective actions, and (iv) verify whether the licensee reported the events !
in accordance with applicable requirement .
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The event described by PIR 1-87-102, the Isolation Condenser Valve IC-2 failure, is discussed in detail below (Section 5.3). .Except as noted below, the-inspector had no further comments and no inadequacies were identifie .3 Isolation Condenser Valve IC-2 Inoperability - Unit 1 On November 30, 1987, during the normal quarterly operability check of isolation condenser valve IC-2 (normally open outboard steam supply valve), the motor operator' tripped while opening the valve. During troubleshooting, the licensee entered the Limiting Condition for Opera-tion (LCO) of Technical Specification (TS) 3.5.E. TS 3.5.E.2 restricts power operation to 40% of full power within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the discovery i of isolation condenser inoperabilit The licensee confirmed that IC-2 operated in the closed direction; because this is the isolation condition (it automatically closes on high steam or condensate flow in the IC in response to a Primary Containment Isolation Group IV signal), the valve was considered operable as related to its primary containment isolation functio On December 1, 1987, the TS LCO (3.5.E) was again entered to cycle IC-2.
l It closed normally but the motor ag61n tripped on high torque while travelling in the open direction. On December 2, the licensee declared
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IC-2 inoperable to disassemble the MOV. They found the spring pack nut loose, which caused spring tension to be released completely. Close in-l spection revealed that the locking allen screw had not been inserted in the nut enough to contact the th. reads although the allen screw had been and was still staked in place. The problem appeared to be a bad thread in the set screw hol The licensee rethreaded the set screw hole, tightened the spring pack nut in accordance with Limitorque instructions, drilled a naw set screw dimple in the threaded area of the shaft, set tha allen screw and staked it in place. When the spring pack nut was tested, it could not be loosened. The valve was returned to full service at 5:30 pm, December 2. The inspector followed the repair effort including the Motor Operated Valve Analysis and Testing System (MOVATS) work performed subsequent to the repair. No deficiencies were identifie IC-2 is a SMB-3 size Limitorque Motor-Operated Valve (MOV) installed as a replacement during the 1987 refueling outage. The inspector learned that no other SMB-3 MOVs had been installed during the 1987 refueling outage. However, two SB-3 MOVs which are similar in design to the SMB-3 were installed for 1RR-2A and IRR-2B, the recirculation pump discharge
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valves. Because these valves serve no purpose in an accident situation other than to close upon receipt of a closure signal from the Low Pres-l
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sure Coolant Injection (LPCI) loop selection logic network, and the failure mode described above occurs only while operating the MOV in the open direction, the licensee plans no further investigation concernino the potential failure of 1RR-2A and 1RR-28 due to this particular failure mechanism. The inspector had no further questions on this matte ___ . ..
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6.0 Observation of Surveillance Activities-- Unit 1 On December 9-11, the inspector observed the following surveillance activities
for procedural adherence, compliance with technical specifications and ad-ministrative requirements, and correction of deficiencies in accordance with
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established administrative requirement SP 4118 - Main Steam Line High Flow Functional Test
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-- SP 406B - Main Steam Line High Radiation' Functional Test
-- SP 404C - APRM Functional Test
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No unacceptable conditions were identifie It is noteworthy' that the in-spector observed the initial use of revision 12 to SP 404C. The author of the revision, an engineer in the I&C department, was present during the testing to verify the accuracy and useability of the procedure revision. The inspec-
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tor verified that all procedure discrepancies identified during the perform-vi .f' ance of the surveillance were corrected in accordance with the requirements 3 ,
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of Technical Specification 6.8.
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i 7.0 Inspection of SIMS Items
+ The following license amendments, which are tracked using the NRC's Safety
[k347 ~ e Issues Management System (SIMS), were sele'ted for review ta verify imple-mentation at Millstone Unit 2:
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License Amendment 88 - Boric Acid Flow Path f' .c - --
License Amendment 90 - Reload, Cycle 6 s '
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License Amendment 95 - Control Element Assembly (CEA) Position Indication
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License Amendment 97 - Pressuriier
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License Amendment 106 - Control of Overtime
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i 7.1 License Amendment No. 88 - Boric Acid Flow Path
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a' Amendment No. 88 provided a Limiting Condition for Operation (LCO) which R _
addresses the operability of flow paths from the boric acid storage tanks f (BASTS) to the reactor coolant system (RCS) and the operability of as-i ;. sociated heat tracin The LCO requirement is as follows:
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"3.1.2.2.1 Two flow paths from the boric acid storage tanks via either a boric acid pump or gravity feed connection and a charging pump to the Reactor Coolant System and one associated heat tracing circuit shall be OPERABLE."
l To verify the above LCO, the inspector performed a valve alignment check i in the BAST area. The manual and motor-operated valves between the BASTS l and the charging pumps were found to be in the correct position with both
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. boric acid pumps in standby. Control room indications were consistent w;th observations in the BAST roo Visible areas of the heat tracing
!< x appeared to be in good condition and the heat tracing was energize Because one or more charging pumps are always in operation, the valve
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alignment from the charging pumps to the RCS was not verified. Based on the aoove observations, Technical Specification 3.1.2.2.1 appeared to be satisfie In the process of verifying valve alignment, it was noted that house-keeping in the BAST area was poo Numerous miscellaneous objects (tools, trash and other material) were in the area and the floor was coated with a white powder (most likely insulation material). Piping insulation was damaged or missing in a number of areas. This finding was identified to the licensee, who initiated actions to clean up the room. Housekeep-ing will be reviewed further during subsequent routine inspection License Amendment No. 88 also included revised surveillance requirements (SRs) for the boric acid flow paths. The inspector reviewed licensee procedures to verify that each technical specification had a correspond-ing surveillance test which implemented these requirement Procedures 2601A, 2601B and 2601C were reviewed and found to be adequate to assure compliance with the associated S .2 License Amendment No. 90 - CEA Drop Time and Auxiliary Feedwater License Amendment No. 90 contains a number of Technical Specifications (TS) that address Cycle 6 operation of Millstone Unit These TS were extensively updated based upon subsequent reload analyses and will be the subject of a separate inspectio Two TS in License Amendment N , Control Element Assembly (CEA) drop times and Auxiliary Feedwater Systems, were not superseded by subsequent changes and are addressed herei The requirements of TS 3.1.3.4, "CEA Drop Time" include confirmation that CEAs drop, upon electrical power interruption, from full out to 90% in-sertion in less than or equal 2.75 second Procedure SP 21010. "CEA Drop Times," March 11, 1986 was reviewed to determine compliance with TS 3.1.3.4. In addition, rod drop data for December 12, 1986 was re-viewed. It was determined that SP 21010 assures compliance with TS 3.1.3.4 and that the December 12, 1986 data showed rod drop times well within the 2.75-second acceptance criteria.
l License Amendment No. 90 also included a change to the SR for the turbine-driven auxiliary feedwater pump. The revised TS 4.7.1.2 is as follows:
"The steam turbine driven pump develops a discharge pressure of greater than 1000 psig on recirculation flow when the secondary steam supply pressure is greater than 800 psig. The provisions of Specification 4.0.4 are not applicable for entry into Mode 3."
The above SR is implemented by Procedure 26108, "Turbine Driven Aux Feed-water Operability," Rev. 7, Ch. 3, March 31, 198 In reviewing Proce-dure 26108, it was ncted that the acceptance criterion for the pump dis-charge pressure was incorrectly given as 1080 psia rather than 1080 psi This error was referred to the licensee for correctio No other proce-I
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dure discrepancies were found. A review of data from 1987 showed accept-able test results and that the correct surveillance interval was being maintained. In the process of reviewing compliance with TS 4.7.1.2 the auxiliary feedwater pump rooms were inspected. The equipment in the auxiliary feedwater pump rooms appeared in good condition and good house-keeping practices were eviden .3 License Amendment No. 95 - CEA Position Indications, Level Band for Safety Injection Tanks (SITS), and Containment Integrit The change to the TS on CEA position indication is associated with a Limiting Condition for Operation (LCO). Since the LCO only provides instructions to operators in the event of a failure, it was not verifi-able by review of procedures or other observable mean The change to TS 3.5.1 associated with the SIT level requires the licen-see to maintain a level of borated water between 1080 and 1190 cubic feet in each of four SITS. TS 4.5.1 requires that SIT level be verified at least every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Indication of SIT Levels is available on Control Room Panel C01 via Level Indicators (LIs) 311, 3El, 331, and 341. The SIT Levels can also be obtained via the plant computer, which appears to be the preferred means. While the TS Limits are in cubic feet, the instrumentation provides indication in "percent of tank volume." Pro-cedure 2619A, "Control Room Shift Checks," requires that the SIT tank levels be recorded during each shif t. On December 1, 1987 the recorded SIT Levels from Procedure 2619A were checked against the levels indicated on panel C01 and good agreement was noted.
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Calculations concerning the correlation between SIT level, as indicated by percentage, and contained borated water volume, were reviewed. The SITS have an inside diameter of 108 inches with a distance between the instrument level taps of 334 inches. The distance from the upper and lower instrument taps to the respective end heads is 5 inches for a total cylindrical height of 344 inche Each end head has a volume of approxi-mately 95 cubic fee This data yields a total SIT volume of 2014 cubic feet as compared to an FSAR value of 2019 cubic fee In addition, Pro-cedure OP2306, "Safety Injection Tanks," Rev. 9, May 10, 1987 states that an indicated level of 60.3% corresponds to 1190 cubic feet of borated water and that 54.2% indicated level corresponds to 1080 cubic feet, which are the limits of TS 3.5.1. Using the data presented above, 60.3%
and 54.2% indicated level corresponds to 1187 and 1081 cubic feet re-spectively. Thus, the licensee's calculations are accurat License Amendment No. 95 changed TS 4.6.1.1, "Primary Containment." TS 4.6.1.1 provides for routine surveillance of containment openings (pene-trations, doors and hatches). Plant procedures 2605A, 2605F and 2605C were reviewed to see if a test demonstrates compliance with each re-quirement of TS 4.6.1.1. The procedures and available data for 1987 were reviewed. It was concluded that the procedures show compliance with TS 4.6.1.1 and that the results and test frequency are acceptabl _ _ _ . _ . _. ___-_________- _ _ _ _
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7.4 License Amendment No. 97 - Pressurizer
' Amendment No. 97 changed the LCO and SR of TS 3/4.4.4, "Pressurizer."
In reviewing the LCO, an error was identified in Amendment No. 97. The previous version of TS 3.4.4 had required that.at least 130 Kw of pres-surizer heater capacity, capable of being supplied by emergency power, shall be operable. The version of TS 3.4.4 issued with Amendment N deleted the requirement that part of the pressurizer heaters be sup-
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plied by emergency power. This is associated with a post-TMI concern that loss of offsite power-could lead to an inability to control RCS pressure unless the pressurizer heaters can be powered from an emergency power source. -The licensee agreed to propose a corrected TS 3.4.4. In
, the near futur Millstone Unit 2 has ample pressurizer heater capability powered from emergency power sources. Plant electrical Bus 22E and 22F (both ,f which are emergency power sources) each supply 160 kw of pressurizer heater With regard to the expanded pressurizer level band implemented by TS 3/4.4.4, the licensee records the pressurizer level during each shift per SP 2619A, "Control Room Shift Checks." A review of data associated with SP 2619A indicates that the revised pressurizer level band it, taing observed and that data is being properly recorded at acceptable interval .5 License Amendment No. 106 - Control of Overtime License Amer.dment No. 106 requires in TS 6.2.2g that administrative pro-cedures limit working hours of unit staff who perform safety-related functions. These procedures should follow the general guidance of the NRC Policy Statement on working hours (Generic Letter 82-12).
The NRC safety evaluation supporting License Amendment 106 states that licensee Procedure NE01.09, "Overtime Controls for Personnel Working at the Operating Stations," acceptably implements Generic Letter 82-1 NEO 1.09 establishes overtime limits and provides for extending those limits by using an overtime authorization form, "Authorization to Exceed
Established Overtime Limits." An NRC audit of employee timesheets was 4 conducted. The audit included the first three months of 1987, when an
, unplanned outage of Millstone Unit 2 occurred. During unplanned outages,
- extensive use of overtime is expected. The audit found several instances of licensee employees working above-limit overtime hours which were not being controlled by use of the NEO 1.09 authorization form. This finding
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was discussed with licensee management. The licensee was asked to review j the use of overtime during the 1987 outage to determine the extent to
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which NE0 1.09 was net properly implemente The licensee reviewed the 4-week 1987 outage and identified the following seven instances in which the overtime limits were exceede .. ..
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Individual Work Period Work Hours A 2/9 - 2/15 73 hours8.449074e-4 days <br />0.0203 hours <br />1.207011e-4 weeks <br />2.77765e-5 months <br /> total & 24.75 hrs in 48 hrs B 1/26 - 2/1' -76 hours C 2/9 - 2/15 76 hours8.796296e-4 days <br />0.0211 hours <br />1.256614e-4 weeks <br />2.8918e-5 months <br /> D 2/2 - 2/8 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> E 2/9 - 2/15 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> F 2/9 - 2/15 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> G 2/9 - 2/15 76 hours8.796296e-4 days <br />0.0211 hours <br />1.256614e-4 weeks <br />2.8918e-5 months <br /> total (40 hrs, in training)
The plant positions working the above above-limit hours inclu'ded duty officer, plant equipment operator, and reactor operator. These indivi-l- duals all perform safety-related functions, NE0 1.09 specifies that "an individual shall not be permitted to work more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period" (Section 6.1.4), and that "an individual shall not be per-mitted to work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any work week (Section 6.1.5). The criteria of LEO 1.09 are made requirements for station personnel by in-corporatien into ACP 1.19, Overtime Controls for Personnel Working at the Operating Nuclear Station ' Failure to control and approve overtime in accordance with NEO 1.09 violates TS 6.2.29 (VIO 50-336/87-29-01).
The inspector noted that excessive overtime could cause fatigue and ad-versely affect the performance of safety-related duties, The inspector noted, however, that for the identified instances, there was no indica-tion that the improperly approved overtime adversely affected plant safet On December 3, 1987, the Unit Superintendent acknowledged the inspector's findings and concerns regarding the need to follow procedures for the use of overtime. Following his review of the 1987 outage activities, the licensee stated that the following actions would be taken to prevent recurrence: (i) the individual involved in the improperly authorized overtime would receive a reprimand; (ii) the overtime policy and guide-lines would be reviewed at department and outage meetings to emphasize the importance of observing the limits and approval controls; (iii) for the upcoming refueling outage, directions would be issued to direct that work schedules would include at least I day off per week, and if 7 days are worked, then the following weekend would be scheduled as off for the individual. The inspector reviewed the licensee's followup actions and concluded that his corrective measures are appropriat Based on the above, no additional licensee response is required. In the future, control of overtime will be reviewed on a sampling basis to as-sure that NE0 1.09 is followe _ _ _ _ _ _ _ _ .
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7.6 Summary l
Review of procedures and observing plant conditions and licensee activi-ties verified that License Amendments 88, 90, 95, and 97 are being ac-ceptably implemented at Millstone 2. That conclusion is qualified as follows:
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The reload analysis-related TS associated with License Amendment 90 were not reviewe The licensee should submit a revised TS to correct an error which occurred with issuance of License Amendment 97 (see Detail 7.4).
With regard to License Amendment 106, additional licensee management
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attention is warranted to assure that TS 6.2.29 is met for the use and control of overtime work (see Detail 7.6).
8.0 Fastener Testing for Conformance With Material Specifications (0 pen) Bulletin 87-02 (TI 2500/26): The NRC issued IE Bulletin 87-02, "Fast-ener Testing to Determine Conformance with Applicable Material Specifications",
dated November 6, 1987, to request licensees to review their receipt inspec-tion requirements for fasteners and to determine through independent testing whether fasteners in stock meet required mechanical and chemical specifica-tions. Item 2 of the bulletin required that the licensee drew a sample of fasteners from safety-related and non-safety related stores, and to obtain the samples with the participation of the onsite resident inspecto During a meeting with representatives from the NUSCO Quality Services Group on December 2, 1987, the inspector reviewed the licensee's plans to sample and test fasteners from Millstone Station Stores in accordance with IE Bulle-tin 87-02. Because the warehouse facilities at the station are common to all three Millstone units, the licensee's action on the bulletin applies to al The licensee stated that the stock currently in use included fasteners that were procured to meet the following 8 ASTM groups for chemical and mechanical properties: A-193 Gr B7, A-193 Gr B8, A-193 Gr 816, A-325 TP 1, SAE J429 Gr 5, SAE J429 Gr 8, A-449, and A-194. The licensee sampling plan was to select 10 fasteners from safety-related stock and 10 fasteners from non-safety-related stock, plus an equal number of nuts for a one-for-one sampling from both the safety and non-safety groups. Additionally, in order to meet the requirements to test for both chemical and physical properties, two of each p,iece would be withdrawn for a total sample of 40 sets or 80 pieces. The material would be selected from the above listed ASTM groups in proportion to the in plant use of materials to the extent determinabl The inspector verified that the licensee's sampling plan met the bulletin req ui remerit s . The licensee stated that testing per Bulletin Item 4 would be completed by Dirats Laboratories in Westfield, Massachusetts, which is a ma-
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terials testing laboratory qualified for this type of testin The inspector:noted that the laboratory was on the licensee'g s approved by the license vendor lis <
< The inspector accompanied licensee personnel on December 7, 1987 to witness withdrawal of material in accordance.with the above sampling plan from stock in Warehouses #3 and #7. A summary of the material selected is provided in Attachment I to the inspection report. In accordance with the TI requirements, materials that did not have manufacturer's markings, or bolts with the manu-facturers marks of KS, J, M, FM, NF, RT, H, A or MS were selected if foun The licensee sent the material offsite and expects to have the-test results within three weeks. The licensee's response to the bulletin is due on January 10, 198 The-inspector has no further questions on this item at the present time. This item will be reviewed further on a subsequent routine inspection following receipt of the licensee's response to IE Bulletin 87-0 .0 Follow-up of Temporary Instruction (TI) 2515/90 (0 pen) Background On June-28, 1980 during a routine shutdown of the Browns Ferry Unit 3 reactor, a manual scram from 36% power failed to insert approximately 40% of the con-trol rods. The root cause was a problem with the scram discharge volume (SDV).
Follow-up on this event at other Boiling Water Reactors (BWRs) revealed a number of deficiencies involving SDV header The corrective measures for this problem are divided into a short and long-term program. The short-term actions were implemented by IE Bulletins 80-14 and 80-17 and their supplements. The objective of the long-term program was improvement of the SDV desig Short-term actions identified in IE bulletin 80-14 were reviewed, closed out, and documented in routine inspection report 50-245/80-17. Short-term actions identified for IE bulletin 80-17 and its supplements were reviewed as docu-mented in inspection reports 50-245/82-17, 50-245/82-22, and 50-245/83-0 The long-term program to improve SDV design is divided into eleven criteri The criteria and licensee actions are identified below: Scram Discharge Header Size Criterion: The scram discharge headers shall be sized in accordance with GE OER-54, and shall be hydraulically coupled to the instrumented volume (s)
in a manner to permit operability of the scram level instrumentation be-fore loss of system function.
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Actions: The licensee .ompleted modifications to the SDV in the fall of-1982 outage utilizing Plant Design Change' Request-(PDCR) 1-84-82, and-Project Assignment (PA)80-144. The modifications included:
1) Installation of a second iristrument volume tank (IVT) for the south-SDV, i.e., two separate SDV's and associated-piping where only one was available before the chang (1) Replacement of two (2) inch piping connecting the SDV and IVT with six (6) inch piping, lii) Installation of redundant vent / drain valves, iv) Increasing the capacity of the SDV to allow for 3.34 gallons per drive, as required in GE OER-5 The design verification of PDCR 1-84-82 identifies the system'as provid-ing a volume required to absorb the water displaced during a scram by multiple redundancy factors of: reducing constrictions imposed by the old scram header by increasing its overall volume; class break locations and hanger designs to ensure full availabilities of the system following a design base accident (DBA), and trip sensors such that multiple signal sources are maintaine The inspector's review of PDCR 1-84-82, and PA 80-144 (Modifications to the SDV), and Safety Evaluation Report (SER) NUREG 1143 paragraph 4. developed no further questions in this area. This item is close B. Automatic Scram on High SDV Level Criterion: Level instrumentation shall be providod for automatic scram initiation while sufficient volume exists in the SD Actions: Licensee drawing 25202-26039 identifies six level sensors per scram discharge instrument volume. Four sensors provide an input to the reactor protection system (RPS) for respective channels A, B, C, and The fifth level sensor provides the "SDV Not Drained" alarm on control room panel 905. The sixth level sensor provides a rod bloc Technical Specification (TS) Table 3.1.1 identified the trip setpoint for high level in the SDV. The trip setpoint is less than or equal to 26 inches above the center-line of the lower end cap to the SDIV pipe weld. TS Table 3.2.3 identifies the initiation of a rod block when SD" level is less than or equal to 14 inches above the lower cap to the SDiv pipe wel According to the TS, the level setpoint on the instrument volumes, which alarms and scrams the reactor, provides greater than 3.34 gallons per drive to accept scram wate;. This function shuts the reactor down while
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sufficient volume remains to accommodate the discharge water and pre-cludes the situation in which a scram would be required but not be able to perform its intended functio Operating Procedure (0P)-302, section 8.10 and 8.11 identifies the set-point for the control room panel (CRP)-905 alarms. The "North / South Discharge Volume Not Drained" alarm setpoint is eight inches above the lower cap to the SDIV pipe wel This item is close Instrument Taps Not On Connected Piping Criterion: Instrument taps shall be provided on the IV and not on con-nected pipin Results: The inspector's review of licensee drawing number 25202-26039, (Flow diagram Control Rod Drive Hydraulic System Headers and Scram Dis-charges Volumes) identified the level instrument taps as being directly l from the instrument volum Upon subsequent review, the inspector physically verified that the location of instrument taps is on the north and south SDIV and not on connected pipin This matter is close Detection of Water in the IV Criterion: The scram instrumentation shall be capable of detecting water accumulation in the IVs assuming a single active failure in the instru-mentation system or plugging of an instrument lin Results: Each SDIV has six magnetrol horizontal level control switche The level control switches are identical in construction Model number:
402-X-EP/VPX-M14H. According to the SER (NUREG 1143) the switches are not subject to the differential pressure problems that caused magnetrol float switches of the vertical acting type to fail at some Boiling Water Reactors (BWR's).
The inspector reviewed control wiring diagrams (CWDs) 555, 580, and 525 to identify the power supplies to each of the level control switche The following table lists the switch identification, purpose, and power supply:
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Level Control Switch N Purpose Power Supply 302-S82A Hi Level Scram Reactor Protection Bus A (RPB A)
302-S82C Hi Level Scram RPB A 302-N82A Hi Level Scram RPB A 302-N82C Hi level Scram RPB A 302-SS2B Hi Level Scram RPB B 302-S820 Hi Level Scram RPB B 302-NB2B Hi Level Scram RBP B 302-N820 Hi Level Scram RBP B 302-N82E Rod Block 120 VAC Instrument Bus 302-S82E Rod Block 120 VAC Instrument Bus 302-NS2F SDV Not Drained 120 VAC Instrument Bus Alarm 302-S82F SDV Not Drained 120 VAC Instrument Bus Alarm In overview, each SDIV (North and South Banks) has four level sensors dedicated for high level SDV scram inpats. Two of the four sensors are supplied electrical power from RPB-A and the remaining two sensors are supplied power from RPB-B. Normal power to RPB-A and -B is supplied by two motor generator sets. The reserve power supply to RPB-A and -B is from MCC-E4. This power supply is mechanically interlocked with both power sources to prevent both supplying a RPB simultaneously. The mechanical interlock also prevents supplying more than one RPB from re-serve powe The trip logic for each of the inputs is "one out of two taken twice." Redundancy is provided with two sensor inputs for each RPS sub-channel (i.e. A1, A2, B1, and 82), with each sensor input located on a respective north and south SDI The inspector concluded that neither single failure in the instrumenta-tion nor plugging of an instrument line will preclude detection of water accumulation in the SDIV. This item is close E. Vent and Drain Valves System Interface Criterion: Vent and Drain functions shall not be adversely affected by other system interfaces. The objective of this requirement is to pre-clude water backup in the scram IV, which could cause a spurious scra Results: The inspector's review of this criterion has not been completed, therefore this item remains open until inspection effort has 'Jeen final-ize . _ . _ -
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.. Vent and Drain-Valves Close on Loss of Air Criterion: The power-operated vent and drain valves shall close under loss of air and/or electric power. Valve position indication shall be provided in the control roo Results: According to FSAR paragraph 4.6.1.2.4 the discharge volume vent and drain valves are held normally open by the application of instrument air pressure to the respective diaphragm operator. The valves close by internal spring pressure upon the removal of control air pressure. Each SDV vent and drain valve is provided with two stem-mounted position switches. Vent and drain valve position indigation is provided on CRP-90 The following valves are identified on CRP-905: SDV-1N, SDV-2N, SDV-3N, SDV-4N, SDV-15, SDV-25, SDV-3S, and SDV-4S. Each valve has an open and shut indication ligh This item is open pending further in-spector review of the power-operated vent and drain valve Operator Aids Criterion: Instrumentation shall be provided to aid the operator in the detection of water accumulation in the IV before scram initiatio Results: CRP-905 provides two alarms to aid the operator in detection of water accumulation in the north and south SDIV's. The alarms are the
"North / South Discharge Volume Not Drained." The alarm setpoint is eight inches above the lower cap to the-SDIV pipe weld. OPS 230-375 (Annunci-ator Alarm and Response) for this partie.ular alarm dictates that the operator verify that SDV vent and drain valves are open if the alarm was not caused by a reactor scram. Subsequent operator follow-up actions are located in OP-302 sections 8.10.6, and 8.11.6, which dictate local level checks for the SDIV and the inspection of possible leakage paths to the SDI If SDIV level were to reach fourtecn inches above the lower cap to the SDIV pipe weld a rod block would be initiated. The high level SDIV reactor scram setpoint is at twenty six inches above the lower cap to the SDIV pipe weld. This item is closed.
i Active Failure in Vent and Drain Lines Criterion: Vent and drain line valves shall be provided to contain the
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scram discharge water with a single active failure and to minimize operational exposure.
[ Results: FSAR Section 4.6.1.2.4 and drawing number 25202-26039 identify l redundant vent and drain valves on the SDIV's. Two in-line vent valves (SDV-1N, SDV-2N) for the north SDIV, and two more (SDV-15, SDV-25) for
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the south SDIV provide redundancy. The drain valves (SDV-35, SDV-45, i
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SDV-3N, and SDV-4N) also provide for in-line redundancy. Redundant vent and drain valves for each SDV are provided to ensure against loss of coolant from the SD Control air is supplied to the vent and drain valves by two three-way solenoid-operated scram dump valves. Upon initiation of a scram, both scram dump valves open, venting control air from the vent and drain valve operators and permitting the vent and drain valves to clos For further protection, control air is supplied to the scram dump valves through two master scram pilot air valves, commonly called back-up scram valve The master scram pilot valves are also interconnected with the RPS to ensure vent and drain valves close upon a scram signal in the event of failure of scram dump of the pilot valves by dumping the air header pressur The inspector had no further questions on this matte This item is close I. Periodic Testing of Vent and Drain Valves Criterion: Vent and Drain valves shall be periodically teste Results: The inspector reviewed procedure SP 608.27 (Scram Discharge Volume Vent and Orain Valve Operability). The objective of SP 608.27 was to verify operational readiness of the SDV and vent and drain valves in accordance with commitments made in response to IE bulletin 80-14 The procedure consists of positioning the discharge volume isolation test switch to the "test position" verifying all eight vent and drain valves close on indication from CRP-905, and subsequently returning the switch to normal and verifying valves open by observing that valve-open lights energize on CRP-90 The inspector reviewed SP 603.29 (Scram Discharge Volume Vent and Drain Valves Operability Test when Shutdown). This procedure verifies opera-tional readiness of the 50V and vent and drain valves when the reactor is shutdown. The test is considered successful when vent and drain valves close in less than 30 seconds on initiation of a manual scram when the reactor is in a shutdown condition and all control rods are fully inserte In conclusion, the inspector verified the adequacy of corrective actions, procedural content, initial conditions, and Technical Specification in-terface for both procedures (SP 608.27, and SP 608.29), and found ade-quate testing of SDV vent and drain valves. This item is close J. Periodic Testing of Level Detection Instrumentation Criterion: Level detection instrumentation and verifying level detection instrumentation shall be periodically tested in plac _ _ _
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I Results: The inspector reviewed procedure SP 4080 (Discharge Volume High !
Water. Level Scram). The procedure functionally tested the following:
, 1) High level scram switches trip setpoint 11) High. level Rod Block switch trip setpoint .;
iii) Volume not drained alarm switch setpoint :
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water to the SDIV and verification of water level and trip set point correlation. The restoration of demineralizer drain and header valves,
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removal of jumpers, SDIV level isolation valves open, alarms clear, and :
notification to the operations staff are identified in section 8 of SP :
408D. This item is closed.
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shall be demonstrated periodically and during each operating cycle by ;
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demonstrating scram instrument response and valve function at pressure and temperature at approximately 50% control rod density,
Results: The licensee responded to this item in a March 20, 1981 letter to the NRC (Mr. W. G. Counsil to Mr. Darrell Eisenhut) on IE Bulletin:
80-17. In the overview of the letter, the licensee committed that, at least once during each operating cycle, the operability of the system will be demonstrated af ter a reactor scram by verifying that the IV level -
trip occurs, vent / drain valves shut, the system can be reset, and the system drains adequately. However, the unit will not be scrammed for the sole purpose of demonstrating the operability of the syste The inspector reviewed ONP-502 (Emergency Plant Shutdown) procedur .
In step 2.8 of ONP-502, the operator develops methods to verify positions !
of vent and drain valves and, if the valves are not closed following a ,
scram, the operator is directed to manually close the valves or reiniti- ,
The inspector expressed concern to licensee management on
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ate a scra the fulfillment of these prior commitments, and subsequent follow-up of the above actions explained in the March 20, 1981 letter. This item re- -
mains ope The unresolved issues described in sections E, F, and K above remain open pending furthar inspector review. These items will be tracked as UNR 50-245/87-33-0 :
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10.0 Preparations for Refueling The inspector reviewed procedures EN 21008 (Refueling Worklist Administrative :
Control), and OP 2209A (Refueling Operations). The review consisted of: pre-requisites for commencement of refueling operations, surveillances and re-i
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quirements in technical specifications as-they pertain to refueling operations, -
and the establishment of communications between the control room, fuel storage -
area and reactor cavity are The inspector reviewed the responsible licensee reactor engineers' past ex-perience and their knowledge in respect to EN 21008 and OP 2209A procedures and the organizational structure during refueling. The reactor engineers
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interviewed had a very good knowledge of the content of and actions found in EN 21008 and OP 2209 j In reviewing EN 21008, the inspector noted a technical specification reference discrepancy for step 3.6 of the procedure. The procedure' specifies Technical Specification 3.9.3 when the step should reference Technical Specification 3.9.3.1 according to Amendment 114 dated January 21, 198 The inspector ,
informed the licensee of this condition, and the licensee plans to correct .
. this discrepancy prior to the scheduled refueling outage. The inspector had
no further comment on this area. No inadequacies were identifie i 11.0 Review of_ Licensee Event Reports
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The following Licensee Event Report (LER) was reviewed to assess LER accuracy, the adequacy of corrective actions, compliance with 10 CFR 50.73 reporting i requirements, and to determine if generic implications existed or if further ;
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information was required. Selected corrective actions were reviewed for 1 implementation and thoroughness as documented below, t
The licensee conducted an integrated leakage test of the liquid portion of '
the Post Accident Sample System (PASS) on 12/23/8 The leakage test was conducted as part of the licensee's corrective actions following his discovery ,
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on 10/27/87 that leakage tests of the liquid PASS lines had not been conducted periodically as required by Technical Specification 6.13 (reference LER 87-42). '
The test was initiated by placing the system online at 9:30 a.m. by opening the PASS suction supply isolation valves from the recirculation system, RR-36 & 37, and walking down the liquid portion of the PASS piping to locate [
1eakage. Leakage was identified from a swage-lock fitting on check valve l PAS-13 in a section of the shutdown cooling suction piping in the shutdown cooling pump heat exchanger room. The leakage water sprayed from the piping .
with the PAS system pressurized to reactor coolant system pressure of about '
1000 psig, Upon discovery of the leakage at 2:30 pm, the licensee terminated the test and isolated the leak by closing valves RR-36 & 37.
. The leakage water that sprayed from the piping was reactor coolant wate l It contaminated portions of the floor, walls and equipment in the shutdown t cooling pump heat exchanger room. The inspector reviewed the licensee's ;
actions to survey and contain and control personnel access to the are Sur-veys showed general area gamma contamination levels in the range of 5000 to 260,000 dpm/100 cm2, and general area dose rates in the range of 8 to 12 mR/hr.
l- Actions were initiated to cleanup the areas affected by the leak during rou- ,
- tine work periods. No inadequacies were identified. No personnel were con- '
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Licensee corrective actions were in progress on 12/24/8/. Initial plans were to complete repairs and retest of the sample piping on 12/28/87.- The resident inspector reviewed the bases for the repair plans and questioned the licensee as to whether the work could be performed sooner. The inspector expressed his concerns that, even though the PASS system is isolated from the primary coolant system and is not used during routine operations, the leakage had the potential to significantly increase the post-accident source term in the Reactor Building following an acciden The licensee tightened the swage-lock fittings. A leakage retest, completed at 10:00 a.m. on 12/24/87, confirmed that-the repair was successful in re-
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storing system leak tight integrit The inspector had no further comments on the licensee's present actions to complete the operational leakage sur-veillance on the PAS syste The inspector found the licensee's response and corrective actions for the above violation of Technical Specification 6.13 to be satisfactory. In view of 10 CFR 2 Appendix C criteria for licensee-identified violations,- no en--
forcement action has been initiated at this time. However, licensee actions to prevent recurrence, namely the issuance of the applicable surveillance procedure, have not yet been completed. For this reason, this item remains unresolved (UNR 50-245/87-33-03).
12.0 On-site Plant Operations Review Committee (PORC)
The inspectne attended Plant Operation Review Committee (PORC) meetings on December 8, 23, and 31. Technical Specification 6.5 requirements for commit-tee composition and quorum were met. The meeting agendas included review of Plant Design Change Records (PDCRs), procedure revisions, Temporary Change Notices (TCNs), and Licensee Event Reports (LERs). The inspector noted at-tention to the importance to safety of the matters under revie No inade-quacies were identifie .0 Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the finding No proprietary information was identified as being in the inspection coverage. No written material was provided to the licensee by the inspecto . - _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _
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ATTACHMENT INSPECTION REPORT 50-245/87-33; 50-336/87-29 MILLSTONE - FASTENER 9AMPLti Ware- QA Tag Material Grade House Location Description Non-QA ID_ Comments A193 B7 3 H1-F-9 Bolts QA MPIA MRIR 1-69-78 1.5-6x9.75 MPIB PO #466879 A194 2H 3 H1-F-9 Nuts QA MP2A MRIR I-86-166 1.5-6 MP2B PO #466879 A193 88 3 24-1-F Bolts QA MP3A MRIR 2-64-80 Sheld 4 3/8-16x MP3B P0 #706373 A194 B8 3 24-1-C Nuts QA MP4A MRIR 2-85-033-1 Shelf 9 3/8-16 MP48 A193 816 3 21-1-H Studs QA MPSA MRIR 1-109-78 Shelft 5 1.375-8x9 MP5B PO #474429 A194 2H 3 21-1-H Nuts QA MP6A MRIR 1-109-78 1.375x8 MP68 PO #474429 C/S 3 D1-A Bolts Non-QA MP7A S/C 03700119 Shelf 8 1/2-13x2 MP78 Bin Q0 6449 C/S 3 01-A Hex Nuts Non-QA MP8A S/C 01000500 Shelf 4 1/2-13 MP88 C/S 3 01-A Bolts Non-QA MP9A S/C 08700217 Shelf 9 5/8-11x MP98 Bin QO 6462 C/S 3 01-A Hex Nuts Non-QA MP10A S/C 01000467 Shelf 4 5/8-11 MP10B Bin QO 6408 C/S 3 01-A Bolts Non-QA MP11A S/C 08700213 (plated) Shelf 10 3/4-10x3 MP11B Bin Q0 6475
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Attachment 2
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Ware- QA Tag Material Grade House Location Description Non-QA 10 Comments C/S 3 01-B Hex Nuts Non-QA MP12A S/C 01000468 (plated) Shelf 4 3/4-10 MP12B Bin Q0 6409 C/S 3 01-B Bolts Non-QA MP13A S/C 08700146 (plated) Shelf 7 3/8x MP13B Marked As KS Bin Q0 6442 C/S 3 D1-A Hex Nuts Non-QA MP14A S/C 01000179 (plated) Shelf 4 3/8" MP14B Bin QO 6386 C/S 3 01-B Bolts Non-QA MP15A S/C 08700372 (plated) Shelf 11 7/8x4 MP15B Marked As J Bin 00 6489 C/S 3 01-B Hex Nuts Non-QA MP16A S/C 01000554 Shelf 4 7/8" Bin QO 6389 A193 B7 7 M1476 Stud Non-QA MP17A PO 20363 #2 1/2-13x2.25 MP178 A194 2H 7 M1521 Hex Nuts Non-QA MP18A P0 20363 #47 1/2-13 MP188 A307 8 7 M1454 Bolt Non-QA MP19A P0 20363 #39 1/2x2 MP19A A307 B 7 M1499 Hex Nuts Non-QA MP20A P0 16018 1/2 MP208 A307 B 7 M145 Bolt Non-QA MP21A P0 20363 5/8x3.75 MP21B A307 B 7 M1525 Hex Nuts Non-QA MP22A Note: No 5/8" 1" MP22B A307 Nuts Avail-able - Used 1" A30 P0 15864
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O Attachment 3
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Ware- QA Tag Material Grade House Location Description Non-QA 10 Comments A193 B7 7 M1415 Studs Non-QA MP23A P0 17283 1.125x4.75 MP23B t A194 2H 7 M1527 Hex Nuts Non-QA MP24A PO 08624 1.125 MP24B A193 B7 7 M1409 Studs Non-QA MP25A P0 17283 7/8x3.75 MP25B A194 2H 7 M1525 Hex Nuts Non-QA MP26A P0 17283 7/8 MP26B A490 TY 1 7 E149 Bolt QA MP27A Note: Bolt Has 1.125x MP27B Special Thread Siz P0 18951 A194 2H 7 E134 Hex Nuts QA .MP28A PO 12907 1.125 MP28B A325 TY 1 7 FF92 Bolt QA MP29A PO 20169 (galvanized) MP29B 1/2x2.75 A194 2H E150 Hex Nuts QA MP30A P0 19519 1/2 MP30B A193 B8 7 FF23 Bolt QA MP31A PO 21517 5/8x3.25 MP31B A194 8F 7 E136 Hex Nuts QA MP32A P0 21928 5/8 MP32B A194 2H 7 E151 Hex Nuts QA MP33A PO 10002 5/8 MP33B A193 87 7 E85 Studs QA MP34A Note: Correct 5/8x3.75 MP34B Length is 3.7 P0 10108 A193 B7 7 E121 Studs QA MP35A P0 10108 3/4x MP35B A194 2H 7 E123 Hex Nuts QA MP36A PO 10108 3/4 MP36B
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Attachment 4 l
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Ware- QA Tag Material Grade House Location Description Non-QA 10_ Comments A193 B7 7 E170 Studs QA MP37A PO 450 1.125x5 MP37B i A194 2H 7 E170 Hex Nuts QA MP38A PO 450 1.125 MP38B A193 B7 7 E69 Studs QA MP39A PO 15322 1.25x MP39B A194 2H 7 E137 Hex Nuts QA MP40A P0 12907 1.25 MP408