IR 05000245/1990009
| ML20055J274 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 07/20/1990 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20055J272 | List: |
| References | |
| 50-245-90-09, 50-245-90-9, NUDOCS 9008020023 | |
| Download: ML20055J274 (21) | |
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t U.S. NUCLEAR REGULATORY COMMISSION
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REGION 1-i-j Report No.:
50-245/90-09
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Docket No.:
50-245 j
License No.
DPR-21 i
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. Licensee:
Northeast Nuclear' Energy Company i'
P.O. Box 270 fiartford, CT 06141-0270
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Facility Name: Millstone Nuclear Power Station. Unit 1
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Inspection at: Waterford, Connecticut l
Dates:
May 15. 1990 - June 25 1990 Reporting
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Inspector:
D. Dempsey, Resident Inspector
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Inspectors:
W. J. Raymond, Senior Resident Inspector
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D. A. Dempsey, Resident Inspector, Millstone Unit'1
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M. Banerjee, Resident Inspector, Oyster Creek Nuclear
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Power Station l,
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Approved by:
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7/20/40
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Donald R. Haverkamp Chieff Date Reactor. Projects Section 4A
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l Division of Reactor Projects
Inspection Summary: Report 50-245/90-09 Areas Inspected: Routine NRC resident inspec' tion of plant operations, radio-logical controls, maintenance / surveillance.- security,. engineering / technical-
L support, and safety assessment / quality verification.-
't Results:
See Executive Summary I
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9008020023 900720 ppR ADOCK 0500 a
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Executive Summary
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i Plant Operations The licensee continued to demonstrate strength in this area through its response to the multiple failures of the "A" recirculation pump seals.
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_Radiolojical Controls
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a In its effort _to maintain personne' radiological exposures as low as reasonably
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achievable, the proper application by_the licensee of health physics work practices contributed to relatively low personnel exposure during recirculation pump seal.eplacements.
t Surveillance and Maintenance Licensee response to the Unusual Event-concerning a failed core spray system motor-operated valve was good. ' Corrective maintenance was performed in a timely manner.
Review of other similar motof operators for the same problem was appropriate.
Security Reviews in this area did not identify any noteworthy findings.
Engineering _and Technical hupport Licensee activities regarding potential plant vulnerability to a house heating system steamline break were extensive and thorough.
Interim solutions to permit the use of the system for drywell nitrogen inerting, thus permitting the timely performance of surveillance on drywell vacuum breaker valves, were weil thought out and conservative.
Regarding the discovery that the feedwater coolant injection system could overload the gas turbine generator under certain accident conditions, the timely development of high quality corrective measures indicated a licensee performance strength-in this area.
Safety Assessment / Quality Verification A violation of the requirements of 10CFR 50.49, env'ironmental qualification of electrical. equipment, was identified by the licensee.
This violation was not cited, since the criteria'of section V.G.1, 10CFR 2, Appendix C, Enforcement.
Policy were met.
The self-identification of this violation is considered to
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demonstrate licensee strength in this area.
Regarding the feedwater coolant injection system / gas turbine generator loading event, the licensee demonstrated at all times a conservative posture and a good regard for safe plant operatio.
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TABLE 0F CONTENTS'
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1.0 Persons Contacted......................................
l 2.0 Summary of Facility Activities.........................
'i 3.0 Plant Operations (IP 71707/93702/62703*)...............
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l 3.1 Control Room Observations.........................
3.2 Plant Tours.......................................
3.3 Review of Plant Incident Reports.................
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3.4 Plant-Shutdown Oue to Recirculation Pump Seal Failure......................................
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4.0 Radiological. Controls (IP 71707/62703).................
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4.1 Posting-and Control of Radiological Areas.........
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4.2 Recirculation Pump Seal Replacement
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Activities........................................
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5.0 Maintenance / Surveillance (IP 62703/61726/92702).........
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-5.1 Observation of Maintenance Activities.............
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5.1.1 Corrective Maintenance on Core Spray
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System Valve 1-05-40............................
5'2 Observation of Surveillance Activities............
5,2.1 Unusual Event - Failure of Core Spray
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System Valve to 0 pen............................
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6.0 Security (IP 71707).....................,~..............
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7.0 Engineering / Technical Support (IP 93702/37828).........
7.1 (0 pen) Unresolved Item 50-245/90-07-02;-
House Heating Steamline Break Concerns............
1 7.2 Modifications to Gas Turbine Generator.and'
Feedwater Coolant Injection Systems..............
8.0 Safety Assessment / Quality Verification (IP 90712/92700/92702/93702/30703)....................
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8.1 Violation of Equipment Environmental
Qualification Barriers............................
i 8.2 (Closed) Unresolved Item 50-245/90-07-03; Gas
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Turbine Generator Technical Specification
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Limiting Condition for Operation Exceeded......... 13-
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8.3 Periodic Reports..................................
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i 8.4 Plant Operations Review Committee.................
8.5 Nuclear Review 0oard...............................15 8.6 Management Meetings................................
- The NRC inspection manual inspection procedure (IP) or temporary instructions (TI) that was used as inspection guidance is listed for each applicable reper -
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DETAILS 1.0.P,ersons Contacted Within this report period, interviews and discussions were conducted with members of Northeast Nuclear Energy Company (NNEC or the licensee) manage-ment and staf f as necessary to support inspection activity.
2.0 Summary of Facility Activities At the start of the inspection period.. Millstone Nuclear Power Station Unit 1 (Millstone 1 or the plant) was operating at 100' percent of full rated power.- On May 18, 1990, the licensee commenced a shutdown required by technical specifications when the "B" core spray system was declared'
The core spray system was declared' operable and full power operation was restored on the same day. On May 19, power was reduced to-25 percent to facilitate a setpoint change to the feedwater coolant in-jection system.
The unit returned to full power. operation later in the day. Between June 13 - 17, the unit was operated between 85 - 100 percent of rated power to adjust a prematurely,lif ting main steam cross around line relief valve. On June 19, a forced shutdown due to high leakage in the drywell occurred.
The leakage was caused by failure of the "A" re-circulation pump seal.
The unit remained off the grid for the balance of the inspection period due to recurring problems with the recirculation pump seal.
A detailed chronology of plant events occurring during the inspection period is included in Attachment 1.
NRC Activities The resident inspection activities during this report period included l
110.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of inspection during normal working hours.
In addition, l
routine review of plant operations was conducted during periods of'
backshif ts (evening shif ts) and deep backshif ts (weekends, holidays, and midnight shifts).
Inspection coverage was provided for 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> during
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backshifts and 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> during deep backshifts.
I 3.0 Plant Operations
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l 3.1 Control Room Observations
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L Control room instruments were observed for correlation between l
channels, proper functioning, and conformance with technical l
specifications.
Using indicators at the main control board, reactor,-
electrical, and safety system lineups were verified to be properly.
aligned. Alarm conditions in effect and alarms received in the control room were discussed with operators.
The inspector periodically reviewed the night order log, tagout log, plant incident report log, key log, and bypass jumper log.
Each of the respective logs was discussed with operation department staff.
No inadequacies
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3.2 plant Tours
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The inspector observed plant operations during regular and backshift tours of the following areas:
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Control Room Reactor Building
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Main Battery Rooms Diesel Generator Room Gas Turbine Building Intake Structure
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Turbine Building Cable Vault During plant tours, logs and records were reviewed to ensure
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compliance with station procec'ures, to determine if entries were l
correctly made, and to-verify correct communication and equipment status. No inadequacies were observed..
3.3 Review of Plant Incident Reports
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Millstone 1 plant incident reports (PIRs) were reviewed during the inspection period to (1) determine the significance of the events; (ii) review licensee evaluation of the events; (iii) verify that the licensee's response and corrective actions were adequate; and (iv)
verify that the licensee reported the events in accordance with i
applicable requirements.
The following PIRs warranted inspector followup and are discussed in the inspection report sections cited below:
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-- PIR_1-90-51, Core spray valve 1-05-4B failed surveillance
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(Sections 5.1.1,5.2.1)
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-- PIR 1-90-56, "A" recircalation pump seal failure (Section 3.4)
-- PIR 1-90-48, EEQ Barrier Violation (Section 8.1)
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3,4 Pla_nt Shutdown Due to Recirculation Pump Seal Failure In May, 1989 during plant _heatup, the "A" recirculation pump seal'
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failed. Details of this event are discussed in Region I. inspection report 50-245/89-12, section 4.4'.
The seal was replaced and functioned satisfactorily until April 12, 1990, at which time second
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stage seal pressure increased to approximately 950 psig, indicating
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potential failure of the seal.
Seal performance and drywell leakage
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rates were closely monitored by the licensee while normal-full power
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operation continued. On June 19, 1990, the "A" recirculation pump
seal failed again causing unidentified drywell--leakage to ' approach-the 2.5 gpm limit of technical specification 3.6.D. Primary-System
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Boundary-Coolant Leakage.
Reactor shutdown commenced at 10:15 a.m.
and a cold shutdown condition was attained ~at 12:00 p.m. on June 2 <-
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t Upon investigation, the licensee discovered severe thermal cracking of the seal rotating face ring, and damage to and inversion of a i
U-cup.
Debris appearing to consist of red iron oxide was found in
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the seal. The licensee postulated that failure had occurred due to
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accumulation in the seal area of corrosion products from the reactor coolant system. Millstone 1 uses the control rod drive-system as the t
. source of seal water injection for seal leakoff flow.. A design
change was implemented'during this inspection period to provide a
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demineralized water source for seal filling and venting, and the fill / vent procedure was changed to preclude backflow of reactor
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coolant system water into the seal.
The licensee replaced the seal assemt'ly, performed a ' hydrostatic -
test of the seal in place, and started up the reactor on June 22.
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Shortly.after reaching rated temperature and pressure, a -low seal
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leak-off flow alarm was received in the control room, and second
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stage seal pressure increased to reactor pressure.
The licensee once
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again shut down the unit and replaced the seal.
The replaced seal was disassembled and found to have seal flange norries clogged with a r
carbon-like debris.
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.I With the replacement seal installed, the unit was started up on June
25. On June 26, during plant heatup, indications of seal-failure-were observed once again and the unit shutdown.
The recirculation i
pump vendor (Byron-Jackson) was called by the licensee to assist in
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troubleshooting the seal problem, A detailed' chronology of these
events is appended to this inspection report as Attachment !!,
The inspector observed portions of the plant shutdown on June 26 and
noted that applicablo procedures were being properly followed.
The inspector verified through discussions with licensae operators a
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thorough knowledge of plant systems a'nd alarms status-by the
operations staff.
No inadequacies were identified.
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Procedures for assembly, installation and hydrostatic testing of the seals were reviewed, and portions of the seal assembly process
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observed. The inspector noted that the procedures contained some quality control hold points, but that no dimensional checks were
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included.
Since trouble-shooting and root-cause determinations are-on going, licensee activities regarding the seal failures and the
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associated maintenance will be detailed in a subsequent inspection report.
4.0. Radiological Controls
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4.1 Posting and Control of Radiological Areas-During plant tours, posting of contaminated, high airborne radiation, and high radiation areas was reviewed with respect to boundary -
t identification, locking requirements, and appropriate hold points.
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The inspector identified no inadequacies.
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'4. 2 Recirculation Pump Seal Replacement Activities -
During this inspection period, the inspector reviewed licensee
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radiological work permits, surveys, and. health physics practices
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associated with recirculation pump seal replacement activities.
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order to reduce contamination. levels:around the pump.: the licenseeL J
f steam cleaned the pump and used oil cloths over the. pump cavity-
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Surveys indicated a 10-12' millirem / hour rad.iation level near the pump. The total accumulated exposure to personnel'for-all three seal replacements was 3 175 man rem.. The inspector (
considered that this relatively low 4xposure indicated a licensee
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a strength regarding keeping personnel exposure as low as reasonably
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The inspector had no further questions.
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5.0 Maintenance / Surveillance h
5.1 Observation of Maintenance Activities b
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The inspector observed and reviewed selected portions of preventive
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and corrective maintenance to verify compliance with regulations, use.
of administrative and maintenance procedures, compliance with codes and standards, level of QA/QC involvemer.t use of bypass-jumpers and safety tags, personnel protection, and equipment alignment and retest.
The following autom ted work orders were included:
M1-90-04516, Ret-of Service Water Pipe leak
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M1-90-05036, Install Temporary Boiler to Nitrogen
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Steam Vaporizer M1-90-04630,. Install Cable for PDCR 1-5-90
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M1-90-04538, Install 14A-14G Tie Breaker Trip
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M1-90-04677, PDCR 1-5-90, Implementation
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M1-90-04678, Gas Turbine Firmware Modification -
and Test M1-90-04606, 1-CS-4B Trip on Overload
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M1-90-04093; -05786; -05861; -05863, Replacement
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of "A" Recirculation Pump Seal M1-90-04616, Replace Lockdown Nuts on 1-CS-4B
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5.1.1 Corrective Maintenance on' Core Spray System Valve 1-CS-4B During performance of a surveillance test of the "B" core spray subsystem on May 18, 1990, the power supply breaker for valve 1-CS-4B tripped on thermal overload.
Licensee-trouble' hooting revealed that s
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the. locking nuts on the Teledyne motor operator torque switch torque spring stud had fallen off.
(The switch is a Teledyne model T-10-40 type toroue switch.) This caused the valve disc to be driven fully into its seat at full motor operator torque and stick in the closed
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position.
The licensee reinstalled the lock nuts in accordance with-
-maintenance procedure MP-710.3, " Overhaul of Teledyne Motorized Valve Operator," and successfully retested the valve.
No damage to the valve was discernible.
The inspector witnessed licensee troubleshooting of'this valve and had no questions re'garding this activity. However, the inspector questioned whether other safety-related Teledyne motor operators might be susceptible-to a simtiar failure.
In response to'thist concern, the licensee inspected a representative sample of-valve motor operators using type T-10-40 torque switches and found.no other
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problems.
In addition, satisfactory inspection results were'obtained
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for type T-40-200 and T-4-10. switches.
As a further precaution the ol licensee intends to add to procedure MP 710.3 a requirement toiapply-l locktite to the torque spring stud locking nuts. The inspector i
concluded that no generic problem regarding the. torque switches-
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j 5.2 Observation of Surveillance Activities l
Through observation and data review of surveillance tests the
inspect.or assessed licensee performance in accordance with. approved.
l procedures and technical specif.ication limiting conditions for-
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operation, removal and restoration of equipment and. review and resolution of deficiencies'.
The following. tests:were reviewed:
SP 411A, Main Steam Line Low Pressure Functional
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Test / Calibration, Revision 7
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SP 621.10, Core Spray System Operability Test, Revision 9
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SP 621.11, Core Spray Remote Valve Indication Check (ISI),
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Revision 2
SP 622.7, LPCI System Operability Test, Revision 15
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SP 668.2, Gas Turbine Emergency Fast Start Test, Revision 13
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MP 710.3, Overhaul of Teledyne.iotorized Valve Operator,
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Revision 15 The inspector identified no inadequacies.-
j 5.2.1 Unusual Event - Failure of Core Spray System Valve to Open
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On May 18, 1990, at-10:45 a.m., with the plant at 100. percent o'f full rated power, during performance-of surveillance procedure-SP-621.10,
" Core Spray System Operability Test," valve 1-CS-4B failed to return to its normally open position by operation-of the-main control board-switch. The valve is the first discharge valve downstream of the "B"
.i core spray pump.
Failure of the valve in the shut position rendered the "B" train of the core spray system, a low pressure emergency core:
cooling system,. inoperable by technical specification (TS) 3.5. A.2, Core Spray and LPCI Subsystems.
The licensee was already.it, a.7-day TS limiting condition for operation action statement due to the -
inoperability of-the feedwater coolant injection system.
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ly, pursuant to TS 3.5.C.4, the licensee initiated an orderly reactor
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shutdown.
In accordance with its emergency plan implementing pro--
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cedures the licensee declared-an Unusual Event emergency classifi-cation at 11:20 a.m. and notified the NRC via the emergency notifi-'
cation system at 11:30 a.m.
The notification was made as required by-
-l 10CFR 50.72 (6)(1)(1)(A),: initiation of 6ny nuclear plant. shutdown i
t o:;uired by plant technical specifications.
l At 11:30 a.m., valve 1-CS-4B was manually-re-opened and its power supply breaker danger tagged open.
The valve performs no-safety-related function in the closed direction-and was backed up by a second, fully operational, motor-operated discharge-valve, After successfully pressure testing the valve at core spray-pump discharge
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head, the "B" core spray subsystem was declared operable and the i
shutdown stopped.
The: Unusual. Event was. terminated by the licensee l
at-12:05 p.m., and full power operation restored by 12:20 p.m.
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The inspector witnessed port' ions of the plant shutdown from the
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control room and verified that licensee. response to this event was
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timely'and appropriate.
Licensee trouble-shooting and maintenance
activities regarding valve 1-CS-4B.are discussed in section 5.1.1 of
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No inadequacies were observed by the Inspector during this event, 6.0 Security Selected aspects of site security were verified to be. proper during
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inspection tours, including site access: controls, personnel searches,
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personnel monitoring, placement of physical barriers, compensatory i
measures, guard force staffing, and response to-alarms and degraded
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conditions.
No inadequacies were identified.
7.0 Engineering / Technical Support
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7.1 (0 pen) Unresolved Item-50-245/90-07-02: House Heating i
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Steamline Break Concerns
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7.1.1 Background On May 1, 1990, the licensee determined that a failure.~of certain house. heating steam (HH) system steamitses would degrade areas.in the turbine building pre'tiously classified as quipment s h onmental qualification (E:Q) mild environments. The areas potent ally af-
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fected included.the switchgear, heating and ventilation _.HVAC), and control rooms.
In addition-to providing heating steam, the system
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supplies steam to the nitrogen system vaporizer for dryvell:inerting,
and sealing steam to the main turbine during startup ard low power
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(1-10 percent of rated power) operation.
The' licensee immediately
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removed the house heating. steam system from service, notified'the NRC pursuant to 10CFR 50.72, and initiated a reportability/ operability evaluation in accordance with its administrative procedures.
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i June 21, the. licensee completed its technical and operability evaluations of HH system steamline breaks with the following results:
j Steamline Break in the HVAC Room
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Failure of the ten-inch HH steamline in this area would result in a l
compartment ambient temperature and pressure increase to 272 degrees-F and 14.9 psia, respectively, in approximately eight minutes..
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could be admitted to the control room via reverse flow through the
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control room veatilation system exhaust duct which discharges into the HVAC room.
Pressure on the fan room wall panels could result in duct damage and carryoverfof steam to the switchgear area.
It is enpected that equipment lost would include.both trains of the standby
gas treatment system (SGTS) and control room and switchgear area
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ventilation systems.
Pursuant to technicai: specification 3.7.B.
loss of the SGTS would require the plant to be placed in a cold
shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
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Steamline Break in the Switchgear Room
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The switchgear room contains both divisions of'the 4160 VAC, 480 VAC, vital and instrument AC and DC safety related switchgear. These
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systems provide operating and control pcner for normal and emergency systems, including emergency core cooling systems. A break of the
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four-inch HH steamline would result in an ambient teraperature of_146 degrees F in approximately five minutes.
The full load design temperature of the switchgear is 104. degrees.F.
The licensee concluded that there is reasonable doubt'that the affected equipment
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in this area could survive!the transient.
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Loss of Ventilation to the Switchgear Room
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Ventilation for the switchgear area is supplied by redundant supply.
(HVS-6A/-6B) and exhaust fans (HVE-15A/-15B). All fans receive power from motor control centers located.in the HVAC room and are vulner-
able to an HH line break in that space. With the plant operating at 100 percent of full rated power, and assuming a design ambient tem-j perature of 104 degrees F, the compartment would reach 122 degrees'F-
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in eight hours and stabilize at 136 degrees F in six-days in the
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event of a loss of ver,tilation.
Using the guidelines of ANSI /IEEE C37.20.2-1987, Standard for "etal Clad and Station Type Cubicle
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Switchgear, the most limiting cubicle load capacity at 122 degrees F
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is 82 perceny of full rated current.-
Licensee calculations demon-strate that sufficient. margin exists between the limiting current and-
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the maximum expected loads on the affected switchgear to assure sys-tem operability. Thus, sufficient time exists to permit installation of temporary ventilation, unit shutdown, or electrical load reduc-
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Loss _of_ Control Room Ventilation
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An HH steam line break in the HVAC room could result in loss of control room ventilation fan HVH-8.
A licensee study conducted in 1987 concluded that, upon loss of control: room ventilation, area temperature could increase to 105 degrees F with doors blocked open -
and non-essential equipment secared.
Sufficient-time exists-to establish the temporary ventilation equipment required to mai_ntai_n
-room habitability.
Rupture of Switchgear Area Steam Heating Coils-l
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The switchgear area' ventilation-' system fans are not environmentally qualified.
The licensee evaluated the effects of high ambient
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temperature, increased air / steam mixture density, and moisture on the fans and concluded-that continued operation in'the degraded environment is reasonably assured.
The. licensee did not analyza the affects of steam / water carryover into the switchgear area, but i
concluded that modifications to the HVAC: system'must be considered l
to preclude this occurrence, i
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Other Potential Failure' Modes
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As a result of its walkdowns of -the switchgear vent'ilation system on i
May 8, the licensee identified other potential safety-issues.
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Section 3.11.1.1.6 ofothe Updated Final Safetf. Analysis Report (UFSAR) states that a new se'.cnic class 1 HVAC system,was
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installed to provide necesst.ry ventilation'to the environmentally
controlled switchgear aret.
However...the '-licensee now concludes that system seismic qualification is i_ndeterminate,'and that there is insufficient assurance that.the system"would be fully-functional after a design' basis seismic. event.-
The switchgear ventilation system was designed and' constructed l
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in 1980-81.
System electrical and pneumatic controls, dampers, and posit _ ion switches are not environmentally or seismically qualified, nor are the control power trains physically separated.
The switchgear. ventilation system will fail upon loss of_ the
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instrument air system. -Since the instrument air system is not qualified or credited for design basis events, ventilation to i
the switchgear is also subject to failure.
At the time of construction, the switchgear HVAC system was not required to meet seismic class I and electricaliciass IE. standards.
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u The licensee-intent was to design.a system at.least as good as the system then existing.
Nevertheless, the licensee procured and installed some major components which satisfy these standards, though the entire system does not. Therefore, the licensee has concluded
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that despite the vulnerabilities listed above, the switchgear HVAC system meets-the design intent of the original system.
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Licensee Responses - Interim Solutions In order to ensure a sufficient supply of nitrogen for drywell inerting,.the licensee installed a temporary boiler.to the nitrogen.
- i system steam vaporizer.
The inspector walked down the system and=
reviewed the safety evaluation to plant design change evaluation i
MP-1-90-057, !' Auxiliary Steam' to.the Nitrogen Steam Vaporizer Using-a Skid Mounted Steam Boiler," and special procedure SP-90-1-05, F
" Containment Inerting Using An Alternate Steam Supply," both dated-i May 30, 1990c The tenorary system is operated at normal system
pressure and retained all existing design interlocks.
The. normal-
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system operating procedure, OP-311,." Containment System," was mrdi-fied to. reflect this temporary. steam supply.
The inspector had no questions regarding use of this system.
On June 21, the licensee completed its operability evaluation of the
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HH system and developed compensatory measures to permit limited use
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of the system for drywell inerting and to supply turbine gland ~
j sealing steam dur.ing startup and operation-at low power.
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inspector reviewed special: procedure SP-90-1-07, dated June.24,1990 and verified that the required measures were incorporated into the
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procedure. These measures-include:
tagging non-essential portions
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of the HH steam system out of service; providing vent paths from the
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HVAC room in case of a pipe break; limiting.the time during which the system is pressurized; and stationing special-watches'to facilitate
system shutdown within five minutes of detecting a. steam leak.
The
inspector concluded that the procedure provides adequate-assurance i
that the plant could be safely operated in.the event of a.HH system i
steamline break.
7.1.3 Conclusion At present, the licensee is evaluating the system modifications
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required to restore unrestricted use of the.HH. system.
The inspector-will continue to monitor licensee efforts in-this area.
A 1973 high
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energy line break study performed by the Unit 1 architect-engineer.
for Northeast Utilities identified the HH system as'a high energy system and incorrectly concluded that the ensuing environmental conditions would be of-no consequence. to safety related equipment.
To ensure that no other high energy sources have been overlooked,-the l
licensee is reviewing'the 1973 study and performing additional plant
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The licensee response: to the HH steamline break issue is
considered by the inspector to be indicative of strength in the area l
of engineering and technical support.
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10-This item is subject to routine resident review of the following issues:
identification of other high energy _ system' vulnerabilities,-
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if any.
implementation of system modifications,to correct the steamline
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break problems previously identified.
update of-the UFSAR to. reflect accurately the as-built
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condition of the relevant HVAC systems and environmental enclosures.
7.2 Modification to G'as Turbine Generator and Feedwat h Coolant Injection Systems On May 12, 1990, the licensee determined that the postulated t.ccident load on the gas turbine generator (GT) was greater than had previously been assumed.
Preliminary calculations showed that the emergency i
load requirement with the feedwater coolant injection system (FWCI)
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in pump runout condition was 11.463 MW.
The Millstone 1 updated final safety analysis report (UFSAR) specifies a GT rating of 11.1 MW at 100 degrees F air intake temperature.
The machine had been tested previously only to approximately 10.2 mw..In _ order to restore the GT'
and FWCI systems to full operability, two plant design change requests
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(PDCRs) were devel'oped, implemented, and tested during this-inspec-tion period.
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PDCR 1-5-90, " Gas Turbine Generator Load and Performance Improve-
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ments," revision 1, dated May 20, 1990, was implemented to permit i
surveillance testing of the GT at greater load and_to permit emer-I gency operation at a higher exhaust gas temperature (EGT);
In addi-tion, in order to prevent overloading of the GT in the ' event of a feedwater line break and subsequent reactor feed pump runout, a re-actor feed pump trip on high EGT was installed, i
PDCR 1-6-90, "One Pump Feedwater Flow Control Setpoint Change,"
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revision 0, dated May 18, 1990, reduced the accident loading of the G/T by reducing maximum FWCI system flow from 9800 gpm to 6500 gpm
(4000 gpm minimum).
The resulting total accident load was' reduced I
thereby to 10.61 MW.
Regarding FWCI system flow reduction, the licensee analyzed the new flowrate for. its effect on the design basis accident analysis described'in the Millstone 1 UFSAR.
For loss'of coolant accident events, the FWCI system is not credited in the analysis.
In the
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event of a high energy line break outside of-the containment, operation of the FWCI system is assumed only to add conservatism to the _results of the analysis; that is, the off-site radiological consequences are less severe if the FWCI system is lost.
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Nevertheless, the licensee chose new flowrates, consistent with
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the load carrying capability of the GT, in order to maximize the available margin of safety in the event of an accident, The inspector reviewed the safety evaluations.for the PDCRs against -
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the accident analyses contained in the VFSAR and concluded that i
all relevant failure modes and safety issues;had been addressed adequately by the licensee.
During plant' operations' review
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committee (PORC) meetings, the inspector observed.that discussions
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were detailed and that a proper safety perspective was maintained.
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Also, the inspector reviewed the special tests listed below to~
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j results were satisfactory.
T-90-1-02, GT Microprocessor Prescalar EG Readout and Exhaust-
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J Gas Relay Trip Test, Revision 0
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T-90-1-03, Gas Turbine Governor Testing, -Revision 0
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T-90-1-04, GT High Temperature Trip Test, Revision 0,
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change 1 SP-90-1-04, Feedwater Flw Co,ntrol Setpoint Change,
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Revision 0
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The change to the feedwater system flow control mode setpoint'was performed on May 19 at 25 percent;of full rated power in order to miniinize the possibility of a plant ' transient.during the work.
Special measures were taken by the licensee.to preclude a reactor
.i vessel level transient event due to recirculation-pump runback or reactor feed pump runout.
During the performance'of all tests, the.
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inspector verified that appropriate technical specification (TS)
requirements were satisfied. ~ On May 20, while' performing' test --
T-90-1-03, the licensee determined that a test step'could not be'
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performed as written and imtnediately secured the test until a PORC'
approved change could be processed.
The inspector considered this j
action to be a good example of the licensee's high. regard for pro-
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cedure compliance.
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By 5:35 a.m., on May 20, all special tests had b'een completed.
I The GT was tested successfully to greater than 10.7;MW:and declared
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operable. Control power for automatic initiation of the FWCI system
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was restored and TS limiting conditions for operation' exited.
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i The scope of the changes involved during this period required a considerable expenditure of licensee technical.and engineering effort g
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within a short p riod of time. The inspector. considered licensee performance in response to this event to be excellent and indicative of strength in this area. The inspector had no further questions regarding the implementation of these design modifications.
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8.0 Safety-Assessment / Quality Verification 8.1 Violation of Equipment Environmental Qualification Barriers During a routine review of Region I inspection report 50-245/89-27,
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i a licensee quality assurance (QA) supervisor identified that a vio-lation of certain equipment environmental. qualification (EEQ) bar-
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riers may have occurred at Millstone 1.
For a period of If, hours on December 23, 1989, the double doors separating the main turbine deck and heating and ventilation (HVAC) areas, and the switchgear area-supply fan discharge plenum doors, had been blocked open in an at-
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tempt to correct a low temperature condition in a main station bat-tery room.-
j Millstone 1 updated final safety analysis report (UFSAR) section I
3.11.1.1.6 describes the environmentally-controlled areas.of,the plant provided to protect equipment important'to safety from +he'
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harsh environments postulated,.in parti by a high energy line break i
(HELB). The switchgear, HVAC, emergency diesel generator and control l
rooms are classified as mild env r,onments. The safety-related
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i equipment potentially affected by the barrier violation are-listed in UFSAR section 3.11.1 and include the standby gas treatment, control room ventila' ion, AC emergency power and DC emergency power systems.
A licensee quality services department surveillance report SS-131,
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dated April 25, 1990, concluded that an EEQ barrier violation had occurred on December 23.
The root cause of the violation was determined to be a lack of formal guidance and. general; unawareness on the part of unit personnel a garding EEQ barriers in the plant.
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On May 11, plant incident report 1-90-48 was written to initiate reportability and operability evaluations. pursuant to licensee i
administrative procedures.
Licensee reportability evaluation REF i
90-23, dated June 4, 1990, confirmed that a breakdown of EEQ
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barriers had occurred and that a main steamline HELB likely would I
have resulted in failure of safety-related equipment in the affected areas.
Pursuant to 10 CFR 50-72(b)(2)(iii), the licensee notified the NRC of this condition on June 13.
In. order to prevent recurrence of this event, the licensee is developing formal direction regarding EEQ barriers, including documentation of existing barriers and formal guidelines for blocking
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open these barriers should the need arise.
The inspector had no questions regarding this corrective action.
The inspector considered the licensee's-identification of and response to this EEQ issue to be consistent with a high regard for the safe operation of Millstone 1.
However, the blocking open of EEQ barriers on December 23, 1989 was a violation of the
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requirements of 10 CFR 50.49.
This licensee-identified vici, tion of low safety significance is not being cited because the cri+eria specified in paragraph V.G.) of 10 CFR Part 2, Appendix C, Enforce-ment Policy (1990), were satisfied.
(50-245/90-09-01)
8.2 (Closed) Unresolved Item 50-245/90-07-03; Gas Turbine Generato(MnicaT$pecification Limiting Condition.or Operation Exceeded This item concerned licensee activities in response to its determi-nation on May 12, 1990, that the gas turbine generator, one of two on-site emergency power sources, had insufficient proven capacity to support calculated design basis accident loads.
By disabling the g
automatic initiation feature of the feedwater coolant injection sys-B-
tem, emergency loads on the GT were reduced to an acceptable value.
Technical specification 3.5.C.3, Core and Containment Cooling Sys-tems, permits continued reactor operation with the FWCI system in-operabic for seven days, af ter which the plant mtst be shutdown and cooled down to less than 330 degrees F within 2', hours.
The expira-tion time for the TS action statement was 8:30 p.m.,
May 19.
The licensee kept the resident inspector fully informed of action in progress to meet the TS limiting conditions for operation action statement for the FWCI system.
Inspection activities included review of plant design change requests (PDCRs), special test procedures, plant operations review committee activities, plant operations, and work in progress.
Throughout the period of concern, May 12 through 20, 1990, plant operation was stable and no unsafe conditions were
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discerned.
Licensee operations and technical staffs demonstrated excellent knowledge of work in progress and its impact on plant systems status.
Millstone 1 management involvement was extensive and a high regard for reactor safety was evident to the inspector.
The licensee requested on May 18 that the NRC staff approve a one-time deviation from plant technical specifications regarding the FW;I system.
The reason for the request was to permit the thorough esaluation and safe implementation of the plant modifications required ta restore full FWCI and GT systems operability. The licensee
> resented its safety assessment and basis for a temporary waiver of compliance from TS 3.5.C 3 in a letter to the NRC staff dated May 18, 1990.
This matter was discussed with the resident inspector and the NRC Office of Nuclear Reactor Regulation and Region I staffs.
NRC Region I granted verbal approval of the request during a conference call with the licensee on May 18, prior to the expiration of the TS action statement.
During the discussions, the NRC staf f requested that the licensee commit to certain actions regarding surveillance testing of modifications made to the FWCI and GT systems.
In a letter dated June 18, 1990, pursuant to this commitment, the licensee submitted a proposed revision to the Millstone 1 TS.
The proposed change will ensure operability of the turbine high exhaust gas i
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i temperature / reactor feed pump trip.by adding'a surveillance require-ment to the TS.
If the trip is determined to be inoperable, either the FWCl system automatic start must be inhibited from the GT or the
GT declared inoperable. The inspector considered this licensee sub-
mittal to be responsive to its commitment to the NRC staff.
In an.
NRC Region I letter dated May-21, 1990, the NRC granted a waiver of j
compliance f rom the seven _ day time limit of TS 3.5.C.3.
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condition for operation. This deviation was considered by the NRCo i
staff to.be acceptable based on the licensee showing that. a dedon" l
basis accident could be successfully mitigated without_ automatic.
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FWCI initiation with no significant increase in accident
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consequences previously analyzed and accepted by the-NRC. :The waiver..
l of compliance remained in effect until 5:35 a.m. 'on May 21, by which time all plant' modifications had been successfully implemented-and j
tested, and_ applicable _TS requirements satisfied. Details of the
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modifications and tests performed by the licensee are contained in section 7.2 of this inspection report.
The inspector had no further
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questions regarding this issue and no inadequacies were_ identified..
i This item is closed.
8.3 Periodic Reports Upon receipt, periodic reports submitted pursuant.to technical specifications were reviewed.
The inspector ascertained whether.any reported information should be classified as an abnormal" occurrence.
The following report was reviewed:
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Monthly Operating Report - May, 1990
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This review verified that the reported information was valid and-included the required NRC data.
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8.4 Plant Operations Review Committee
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The inspector attended three plant operations review committee meet-ings during the inspection period. Meeting agenda-included review and
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i approval of plant design modifications, setpoint. change requests, procedure revisions, plant incident reports, and technical specif t'-
cation change requests.
The committee discharged its functions in accordance with relevant requirements and demonstrated through de-tailed and frank discussion an appropriate regard for nuclear safety.
No inadequacies were identified.
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8.5 Nuclear Review Board
'During this reporting period the inspector attended a nuclear review board meeting on June 12, 1990.
The board reviewed prior Region I inspection report findings, licensee event reports, and previous plant operations review committee minutes.
The PORC minutes review was particularly detailed and probing. Also, a status report on the-Millstone 1 design basis reconstruction program was presented.
The NRB members demonstrated a questioning attitude toward theLissues.
presented for their review.
Discussions reflected the' variety of technical backgrounds in attendance.
The NRB generally meets on a-monthly basis, exceeding the' technical specification requirement for semiannual meetings.
The meeting was well attended and members ap-peared to have been well. prepared. No inadequacies were observed.
8.6 Management Meetings Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings.was also discussed at the conclusion of the inspection.
No proprietary-information was covered within the scope of the inspection.
No written material was given to the licensee during the inspection period.
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ATTACHMENT 1 Millstone Unit 1 Status I
i May 15 Unit at 100% power.
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May 18'
"B" core-spray system declared inoperable due to failed valve l
surveillance test at 10:45 a.m.
Commenced reactor shutdown per j
technical specification and declared an Unusual-Event emergency
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classification.
Valve-restored, Unusual Event terminated and full a
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power operation resumed by 1:47 p.m.
May 19 Reactor power reduced to 25% at 7:10 'a.m. to char ge feedwater coolant injection system flow control setpoint.
Modification and
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testing completed, and full power-operation resumed at 4:30 p.m.
Reduced power to 90% at 4:45 p.m., and again at.5:30 p.m., due
't to main steam crossover line relief valve lif ting. Holding at 95%
reactor power.
May 20 Reactor power at 100% at 8:47 a.m.
June 7 Reactor power at -65% for main steam isolation valve and turbine stop valve testing.
Increased power tb 75% for condenser mussel cook.
Full reactor power at 12:32 p.m.
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Reactor power between 85% - 100% due to main steam cross around line relief valve lifting prematurely.' Setpoint adjustments
completed and reactor power at 100% at 6:071p.m., June 17.
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June 19 Drywell leakage increased due to failure of "A" recirculation pump seal, Commenced reactor shutdown at 10:15 a.m.
Unit i off the
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grid at 7:00 p.m.
Mode switch in shutdown at 10:32 p.m.
June 20 Plant in cold shutdown at.12:00 p.m.
June 22
"A" recirculation pump seal replaced. Commenced reactor startup at 9:35 p.m.
Reactor critical at 10:50 p.m. -
June 23
"A" recirculation pump seal failed during plant heatup.
Commen.ced reactor shutdown at 9:45 a.m.
Plant in cold' shutdown at 7:00 p.m.
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June 25
"A" recirculation pump seal replaced.
Commenced reactor startup at 12:57 p.m.
Reactor critical at'1:56 p.m.
Commenced plant heatup at 7:00 p.m.
Reactor power at 20% on intermediate range 9 at end of the inspection period.
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. ATTACHMENT II
"A" Recirculation pump Seal Replacement
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March 9 Reactor power at 40%1
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April 3 Shutdown due-to steam leak April 4 A recirculation pump secured for maintenance, discharge valve closed April 7 Started "B" recirculation pump B--
April 7
- Reactor critical
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April 12 Low first stage seal leakage alarm on "A" recirculation pump, second
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stage seal: pressure is approximate y 950 psig.
April 13
"A" recirculation pump low seal flow alarm cleared April 22 High first stage seal leakage alarm "A" recirculation pump
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May 10
"A" recircu'lation pump high first stage seal leakage. alarm coming in and out, seal pressure of second stage seal cycling.from-500 to 1,000 psig.
May 10 Ten minutes later, "A" recirculation pump first stage seal leakage alarm clear and second stage seal pressure holding at approximately-750 psig.
May 10
"A" recirculation pump first stage seal leakage : low alarm, seal
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pressure oscillating between 750 and 875 psig.
May 25 Drywell floor drain leakage 1.06 gpm graphing leakage.
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May 26 Drywell floor drain leakage 0.69 gpm.
i May 27 Stoppea graphing drywell leakage, three consecutive readings less than 1.0 gpm.
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June'4
"A" recirculation pump seal; first stage seal 1000 psig, second
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stage seal 250 psig.
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June 18
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Drywell floor crain leakage 1.7 gpm.
June 19 Plant shut down due to increase in-drywell leakage, caused by the-
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failure of the "A" seal.
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Upon disassembly of this seal severe thermal cracking is evident in
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the titanium carbide seal and one of the U-cups shows signs of in-version.
The U-cup inversion could have possibly occurred as a re-l sult of the seal heating up and melting a portion of the U-cup,
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leaving excessive room between the follower and the rotatihg face for-
the U-cup'to invert.
June 23 Reactor critical, plant heatup in progress.. The.first and second
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stage-pressures are at reactor pressure and there is a low seal leakoff alarm.
Reactor shut down.
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The seal is disassembled and hydrostatically tested; The second
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stage orifice is plugged with a black carbon-like material.
June 24 New seal installed and hydrostatically tested in. place.
June 25 Recirculation pump / seal filled and vented.. Flushing completed g
satisfactorily.
Reactor critical and plant heatup in progress.
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June 26 External leakage discovered from second stage seal.
Commenced reactor shut down.
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