IR 05000387/1985026
| ML17139D203 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 09/13/1985 |
| From: | Jacobs R, Plisco L, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17139D202 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-700, RTR-NUREG-737, TASK-***, TASK-TM 50-387-85-26, 50-388-85-21, GL-82-33, IEB-84-03, IEB-84-3, IEIN-84-93, NUDOCS 8510020080 | |
| Download: ML17139D203 (40) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/85-26 50-388/85-21 Docket Nos.
50-387 CAT C
50-388 CAT C License Nos.
NPF-14 NPF-22 Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Al 1 entown Penn s 1 vani a 18101 Facility Name:
Sus uehanna Steam Electric Station Inspection At:
Salem Townshi Penns lvania Inspection Conducted:
July 29 1985 Au ust 25 1985 Inspectors:
.
H. Jacobs, Senior Resident Inspector date R. Plisco, Resident Inspector
~V'gsJ~s date Approved By:
. Strosnider, Chief actor Projects Section 1B, DRP date Ins ection Summar Areas Ins ected:
Routine resident inspection (U1 - 61 hours7.060185e-4 days <br />0.0169 hours <br />1.008598e-4 weeks <br />2.32105e-5 months <br />; U2 - 51 hours5.902778e-4 days <br />0.0142 hours <br />8.43254e-5 weeks <br />1.94055e-5 months <br />)
of plant operations, licensee events, open items, surveillance, maintenance, IE Bulletins, TMI Action Items, and Unit 1 license conditions.
Results:
Review of Unit 2 scram of August 5, 1985 found that systems functioned as designed and the licensee is reviewing surveillance procedure controls (Detail 3.3); review of licensee response to IEB 84-03 found that the NSAG report was very thorough and corrective actions are necessary to improve main-tenance and operation of the reactor cavity seals (Detail 6.0); review of, the current status of TMI Action Plan Items showed they are either complete o'r on schedule for completion (Detail 7.0); diesel generator ail dryers have experienced operational problems and the licensee is taking adequate corrective action (Detail 8.0).
No violations were identified.
8510020080 850919 j
PDR ADOCK 05000387
~
~.
DETAILS 1.0 Followu on Previous Ins ection Items 1. 1 Closed Violation 387/83-24-01
- Ino erable Off as Hydro en
~Anal zers In November 1983, the licensee identified that both trains of the Offgas Hydrogen (H2) Analyzers had been inoperable for two days due to the return isolation valves being closed.
This involved a
Technical Specification violation and was reviewed in Special Inspection 50-387/83-24 'he cause of the violation was that,itic system procedure indicated that there were two valves labeled'6973A and two labeled 06973B although one of each of these valves is a
return valve and the other a supply valve.
The operator performing the lineup was only able to find one valve labeled 06973A andi',one labeled 06973B.
These were the supply valves.
The return valves were not opened.
In response to the violation, the licensee revised the operating procedures to clarify that there are two supply and two return valves for the hydrogen analyzers.
The valves themselves were relabled with easier to read labels.
The General Operating Procedure for heatup was revised to identify placing the hydrogen analyzers in service per the offgas system operating procedure.
AD-(A-303, Shift Routi'ne, was revised to require maintaining a log of all control room annunciators, and training was conducted for all shifts.
The inspector verified that the above procedure changes were made and that the operators were trained on the event.
1.2 Closed Violation 387/84-14-01:
Manual Containment Isolation Valve Not Locked as Re uired 1.3 In April 1984, the inspector identified that four manual local leak rate test (LLRT) valves were not locked closed as required.
These are manual containment isolation valves.
In response, the licensee locked closed these valves and initiated a review of all containment penetrations.
Subsequently, in July 1985, the inspector identified a
manual containment isolation valve in the Unit 2 RCIC system, which was not locked as required.
A Notice of Violation was issued for this occurrence in Inspection Report 50-388/85-17.
The licensee's followup actions for thi s violation will be reviewed under violation 388/85-17-01.
Closed Violation 387/84-18-01
- Reactor Bui ldin Ventilation Zone Cross-Connection In April 1984, the licensee identified that Reactor Building (RB)
Ventilation Zones II and III were inadvertently cross-connected due to the Unit 2 drywell ventilation hatches and personnel airlock'oors
to the drywell being open at the same time.
This allowed air>> from the refueling floor (Zone III) to communicate with Unit 2 RB (Zone II) via the drywell.
This condition is prohibited by the Technical Specifications.
The concern of the violation was that operators did not have strict control over drywell head removal or ventilation hatch opening, which led to this violation.
t In response to the violation, the licensee revised the maintenance procedures for reactor head insulation installation and drywell head removal/installation.
These procedures now require shift supervision to specifically authorize drywell head removal, removal of head spray piping and instrument lines, or opening drywell head area hatches.
The primary containment control administrative directive, AD-(A-309, was revised to include a caution about not having the drywell Ij equipment or personnel hatches open when the drywell head is removed or the drywell head area hatches are open.
A maintenance instruction, MI-PS-005, was issued to provide guidelines to the maintenance planners for minimizing the likelihood of violating secondary containment when performing maintenance.
Operator training was conducted on the event.
The inspector verified completionI of the above corrective actions.
Closed Ins ector Followu Item 387/85-01-03
- Diesel Generator
~Start Lo In January 1985, the inspector identified that Significant Operating Occurrence Reports (SOORs)
were not prepared for several diesel generator (D/G) trips.
The licensee indicated that the Dieseli)Start Log instruction, OI-024-002, would be revised to emphasize preparing a
SOOR for all D/G trips.
The inspector reviewed OI-024-002 Revision 1 dated March 25, 1985.
The form attached to this instruction is used by operators to r~ecord information for a D/G start.
The form now specifically requires shift supervision review of the information and initiation of a SOOR for all D/G trips, valid or non-valid.
The form is also better, organized to allow proper evaluation of whether the D/G start i,s valid or non-valid in accordance with Regulatory Guide 1. 108 an'd to explain the cause of any failure.
Inspector review of the D/G Istart log entries have identified no further discrepancies.
Closed Violation 387/83-24-02
LCO Violation for 4KV Breaker
~A1i nment In October, 1984, the licensee identified that they failed to follow the requirements of the Technical Specification (TS) Action Statements for loss of independence of offsite power sources.
TI he incident involved a misinterpretation of the TS when a offsite source breaker to one 4KV bus was opened for preventive maintenance.
The licensee should have survei lied the remaining power sources.
Tti s
occurrence was reviewed in Special Inspection 83-24 and discussed at an enforcement conference.
In response, the licensee trained all operators on the occurrence and correct interpretation of TS 3.8. 1. 1.
There was some confusion as to whether opening one source breaker to one 4KV bus required testing of all four diesel generators (D/G).
By memorandum dated June 28, 1984, NRR clarified that this condition would require testing of the associated D/G only.
The licensee also revised the preventive maintenance work authorizations for 4KV breakers to reflect the correct TS references.
The inspector verified that the aboveIactions were completed.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciators were reviewed.
Nuclear Instrument panels and other reactor protective systems were ex'amined.
Effluent monitors were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability.
During entry to and egress from the protected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging,
'and availability of radiation monitoring equipment.
The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection perjod.
Sampling reviews were made of tagging requests, night orders, the
~ bypass log, Significant Operating Occurrence Reports (SOORs),
and gA nonconformance reports.
The inspector observed several shift I
turnovers during the period.
During review of the SOOR log, the inspector noted that there have been three recent occurrences concerning failure of the turbine control valve (TCV) circuitry.
On June 16, 1985, during surveillance test SO-293-001
"Meekly Turbine Valve Cycling" No.
4 TCV failed to initiate a
TCV fast closure signal when the test pushbutton was depressed.
IEC investigated and found a loose amphenol connector in the test mode fast closure circuitry.
On July 27, during the performance of S0-293-001, No.
4 TCV did not fast close.
A loo'se amphenol was again found on the control valve and it was tightened.
The remaining control valves were also inspected and a loose amphenol was found on No.
1 TCV.
On August 4, 1985, during S0-203-001,I No.
TCV failed to fast close.
IKC found the amphenol loose and tightening corrected the problem.
In response to these three e'vents, I&C tightened and lockwired the amphenol connectors for the TCVI circuitry during the recent Unit 2 outage.
!
rI
2.2
appear to be loosening due to vibration.
The amphenols for Unit 1 are scheduled to be tightened during the next available outage.
The licensee also stated that only the test mode circuit was affected, and the operation of the valves fast closure feature would hav'e properly activated the RPS instrument channel.
Station Tours The inspector toured accessible areas of the plant, including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, security control center, diesel generator building, ESSW pumphouse, and the plant perimeter.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping',
security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identified.
3.0 Summar of 0 eratin Events 3.1 Unit
3.2 3.3 Unit 1 operated at or near 100 percent power for most of the inspection period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments and surveillance testing.
Unit 2 On August 5, 1985, at 8:20 a.m.
the Unit 2 reactor scrammed due to an IKC technician error during surveillance testing of reactor wat'er level instruments.
A lead was lifted on the 'B'eactor water ~'level instrument while it was selected for use by the feedwater level'ontrol system, which caused a recirculation pump runback, and an increase in feed pump demand.
Reactor water level increased to,'4 inches, causing a trip of the main and reactor feed pump turbines, and subsequently a reactor scram.
The plant was cooled down to~
Operational Condition 4 and deinerted in order to perform corrective maintenance inside containment.'he unit returned to operation; on August 7, 1985.
(See Detail 3.3).
Unit 2 Reactor Scram Durin Surveillance Testin On August 5, 1985, at 8:20 a.m.
the Unit 2 reactor scrammed due[,to an 18C technician error during surveillance testing on reactor water level instruments.
During the performance of surveillance procedure, SI-245-201,
"Monthly Channel Functional Test of Feedwater System/Main Turbine Trip System, PDT-C32-N004A,B,C" an I&C technician lifted a lead on the 'B'eactor water level instrument circuit with the)
feedwater level control system logic switch selected to the
'B'osition.
Lifting the lead effectively inputs a false low reactor vessel level input signal (zero 'inches) to the circuit.
The ~~logic circuit provides input to the recirculation flow control system and the feedwater level control system.
The false low level placed the recirculation pump limiters into effect, causing a recirculat~ion pump runback to minimum speed (30%).
The feedwater level control system sensed a low level and increased feed pump demand to maximum.~,,
In approximately 25 seconds reactor vessel level reached 54 inches, initiating a trip of the main and feedwater pump turbines.
The main turbine trip caused a reactor scram on turbine control valve fast closure.
Reactor power had decreased from 100 percent to 87 percent prior to the scram due to the recirculation pump runback.
NoIsafety relief valves lifted during the transient and reactor pressure peaked at approximately 1060 psi.
No ECCS actuations occurred.
RCIQ was manually initiated by the operators to maintain reactor vessels level.
Following the scram, the unit was cooled down to Operational Condition 4.
The reactor vessel level instrument lead was lifted in accordance with the surveillance procedure in order to install a transmitter simulator in the circuit.
The procedure required the technici'an to obtain the Shift Supervisor's concurrence to perform the surveillance testing of PDT-C32-N004B and to verify the level logic switch I'elected to the "A LEVEL" at control room panel 2C651, prior to testing the 'B'etector.
The Shift Supervisor's concurrence was obtained but the switch position was not changed by the operator nor adequately verified by the technician.
Prior to the scram, at 3:50 a.m. August 5, it was determined during surveillance test S0-284-001,
"Monthly Functional Test of MSIVI Closure RPS Instrumentation," that relays for the 'B'nboard MSIV 10 percent closure did not reset when the test pushbutton was released.
Troubleshooting conducted following the scram found that the valve limit switch inside containment was the suspect component.
The containment was deinerted, and a drywell entry performed to repair the limit switch.
Repairs were also performed in containment on the
'A'RM drive, RHR injection check valve 2FOSOB air cylinder, and several instruments.
The major work activity accomplished in the outage was the repair of the 5A Feedwater Heater normal level control and emergency dump valves.
Following completion of the repairsI and closure of containment, the Unit was started up on August 7.
i~
The inspector reviewed plant operator logs, recorder traces, log book entries, the sequence of events printout, safety parameter display system data, and GETAR's traces concerning the scram.
The inspector also attended the post-trip review meeting and the PORC startupII meetin I The licensee noted during the post-trip review process that the No.
turbine bypass, valve did not indicate open on the sequence ofIevents log, as would have been expected, and is investigating the sensor.
Tt was also identified that although SPDS and GETAR's did notI indicate an SRV lift, and reactor pressure only reached 1060 psig, the tailpipe temperature recorder indication for the 'N'afe(y relief valve increased about the time of the scram, and then decreased slowly down to normal.
The relief set pressure for,the
'N'RV is 1106 psig.
The licensee has attributed the temperature increase to weeping of the SRV during the pressure transient.
The licensee identified several possible corrective actions related to the performance of surveillance procedures that may prevent recurrence of this type of event.
Although sufficient precautionary steps were already present in the procedure, the licensee is planning to conduct a
Human Performance Evaluation of the event to determine if other effective methods may be utilized.
For example, the ',current surveillance procedures have the steps and sign-offs in separate sections of the procedure.
This requires the technician to fl~ip back and for th between each step of the procedure.
Also, one surveillance procedure tests all three channels, and the steps are performed in succession without a definitive break between channels.
OtherI options were also discussed at the PORC meeting and are being I
reviewed.
Based on inspector review of the associated data and attendance at the noted licensee meetings, the safety system equipment functioned as designed during the transient and the corrective actions tat>en or planned to be taken prior to resumption of facility operation were adequate.
The inspector will review the licensee's corrective actions concerning surveillance procedural controls in a subsequent inspection.
(388/85-21-01)
4.0 Licensee Re orts In-Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the I
accuracy of description of the cause and adequacy of corrective.'ction.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
Thel following LERs were reviewed:
Unit
- 85-026-00, HPCI Turbine Stop Valve Oil Leak
~
~
gf V
T t'
Unit 2
"Discussed in Detail 4.2.
"Previously discussed in Inspection Report 50-387/85-21; 50-388/85-19.
4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1), the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was reviewed by licensee, and that'ontinued operation of the facility was conducted in accordance with Technical Specification limits.
The following findings relate to the LERs reviewed on site:
4.2.1 LER 85-026 HPCI Turbine Sto Valve Oil Leak On June 24, 1985, during testing of the High Pressure Coolant Injection (HPCI) System an oil leak was discovered on the HPCI Steam Stop Valve oil supply line flange.
The leak was severe enough that the turbine was shutdown, immediately and testing was secured.
Oil level in the oil reservoir dropped approximately one inch during the run.
Investigation revealed the nuts securing the flange were very loose.
Maintenance retorqued the flange bolts and added approximately 20 gallons of oil to the reservoir.
A leak test was performed and the system was declared
,
operable on June 25, 1985.
The system had been operated for 2-3 hours approximately one week prior to this event, but no leaks were observed.
The licensee reviewed maintenance records to determine if any activities had been performed on the valve, but none could be identified.
Licensee discussions with the vendor indicate that no causes of oil leakage due to vibration have been reported.
The root cause of the loose bolts could not be determined.
Unit 1 completed an extensive outage on June 8, 1985.
Work was performed on the HPCI system during the period, but subsequent testing did 'not identify any leakage.
The licensee has applied torque paint to the flange bolts and is periodically inspecting them to determine if vibration is causing the bolts to loose I'
't W
I'
4.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to'etermine that the report included the required information; that test results and/or supporting information were consistent wi~th design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems, and whether any information in the report should be classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
Monthly Operating Report July 1985, dated August 12, 1985 The above reports were found acceptable.
5.0 Monthl Surveillance and Maintenance Observation 5. 1 Surveillance Activities The inspector observed the performance of surveillance tests t'o determine that:
the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and,"
appropriately resolved; and the surveillance was completed at the required frequency.
These observations included:
TP-152-013, HPCI Vibration Analysis Test Run, performed on August 7, 1985 S0-024-001D, Monthly Diesel Generator Operability Test, performed on August 15, 1985 SI-278-319, Unit 2 Semi-Annual APRM Calibration on the 'C'PRM performed on July 29, 1985 No unacceptable conditions were identifie.0 IE Bulletins and Information Notice Followu 6.1 IE Bulletin No. 84-03:
Refuelin Cavit Water Seal IE Information Notice No. 84-93: Potential For Loss of Water From the Refuel in Cavit IE Bulletin No. 84-03, "Refueling Cavity Water Seal,"
was issued on August 24, 1984 to notify licensees of an accident in which the refueling cavity water seal failed and rapidly drained the refueling cavity, and to request certain actions to assure that fuel uncovery during refueling remains an unlikely event.
The licensee was requested to evaluate the potential for and consequences of a refueling cavity water seal failure and provide a
summary report of the actions.
The evaluations were to include consideration of: gross seal failure; maximum leak rate due to'i failure of active components such as inflated seals; makeup ca'pacity; time to cladding damage without operator action; potential effect on stored fuel and fuel in transfer; and emergency operating procedures.
IE Information Notice No. 84-93, "Potential for Loss of Water From the Refueling Cavity," was issu'ed on December 17, 1984 to alert licensees to features in some BWRs that may have a significant',
potential to cause loss of water in the refueling cavity.
The",,Notice discussed that some pneumatic/flexible seals may be susceptible to damage from the impact of dropped objects after the cavity is flooded.
It also discussed possible drainage paths through the RHR shutdown cooling valves and cavity drain lines.
The inspector reviewed the licensee's response and an independent review performed by the Nuclear Safety Assessment Group (NSAG)~ito ascertain whether the information submitted by the licensee in; response to the bulletin is technically adequate, satisfies the'equi rements established in the bulletin, and represents the action taken by the licensee.
6. 1. 1 Licensee Res onse to IE Bulletin 84-03
The licensee submitted their response to the bulletin', on November 26, 1984 (PLA-2363).
The report provided the results of the licensee's evaluation of the potential for and consequences of a refueling cavity water seal fai lure.
The Susquehanna reactor well water seals are situated one above the other in a narrow annulus between the drywell and the reactor cavity.
The two nylon-reinforced synthetic rubber seals are manufactured by Presray Corporation.
The seals are inflated by instrument air (maximum system pressure of 107 psig)
and prevent leakage from the reactor well to secondary containment.
A keeper is located upder the lower seal to help maintain the seal's position in the
The upper seal's wedge design precludes its slippage.
The seals are designed to accommodate all credible crevice deflections without leaking.
The licensee noted that extensive testing has been performed on the seals by the vendor.
A cyclic loading test was performed during 1974/75 in which a seal was inflated to 20 psig and deflated 1,500,000 times without failing.
In 1979 a "dead load" qualification test was performed by attempting to force a seal through a gap equivalent to the postulated post seismic gap between the drywell and reactor cavity.
A maximum deflection ofi I/2 inch was noted at the top of the seal when a force of 75 feet of water was applied (actual possible maximum is 25 feet).
The seal could not be forced through the gap'.
The system design at Susquehanna includes leak detection capability.
Leak detection lines are located in a hollow area directly beneath the lower reactor well seal, and are instrumented with a level switch which provides a local alarm.
Any leakage past the top seal can be detected by opening a valve which allows flow through a flow indicating switch.
Reactor well water level is also monitored.'akeup to the fuel pool can be supplied from the Demineralized Water System, RHR System, ESW System and Refueling Water Transfer System.
The licensee's response concluded that due to the redundant design of Susquehanna's seals and the keeper/wedge design to hold the seals, the leakage of the reactor well water seals is a very low probability event, if the seals are maintained properly.
Rapid drainage of the reactor well due to gross failure was not considered credible, since multiple failures are required.
The licensee did not evaluate the potential consequen'ces of a refueling cavity water seal failure since rapid drainage was not considered credible.
They also did not discuss evaluation of the potential effect on stored fuel and', fuel in transfer and the emergency operating procedures.
NSAG Evaluation of Loss of Water from S ent Fuel Pool'vents In December 1984, the Nuclear Safety Assessment Group,,
(NSAG) issued a report on the "Implications of Loss of Water From the Spent Fuel Pool Due to Reactor Cavity Seal Failure or Other Causes."
The NSAG review of the equipment and procedures in use at Susquehanna found that, while a massive failure of the reactor cavity seal is unlikely, loss of level in the spent fuel pool is a credible
occurrence and the consequences could be severe.
TIIe review identified several credible avenues by which"water could be drained from the reactor cavity spent fuelIpool complex.
The most notable of those is via the 20 inch suction piping of the Residual Heat Removal (RHR) system.
Other conclusions of the report were:
The design of Susquehanna is inadequate to properly cope with the radiological consequences of a credible loss of water from the spent fuel pool.
In the worst case, water level could drop to within five inches of the top of the irradiated fuel stored in the spent fuel pool causing excessive radiation levels on'he 818 foot elevation of the reactor building.
The FSAR does not consider the radiation consequences of~ a loss of level in the spent fuel pool.
The cavity seals are not even discussed in the FSAR.
The licensee's current emergency and operating
~,',
procedures and training are inadequate to cope with a credible loss of water from the spent fuel pool".
The probability of reactor cavity seal failure,'lthough very low, is enhanced because proper procedures are not in place and proper testing and maintenance have not been on the seals.
Based on their detailed review, NSAG provided some recommendations for corrective action regarding the preventive maintenance, inservice inspection, testing, and leakage detection/monitoring system which could improve the licensee's capability to prevent and handle a loss of, spent fuel pool water level.
The majority of the recommendations involved procedure revisions and development, and additional operator training, and were acted upon pri'or to the Unit 1 first refueling outage
~pindin s
The licensees response to the IE Bulletin did not adequately discuss all of the evaluations required.
IThe consequences of a refueling cavity water seal failure was not evaluated since the licensee considered a gross failure not credible.
Additionally, the potential effect on stored fuel and fuel in transfer and the emergency operating)
procedures was not discussed in the response.
The NSAG report was a thorough and complete evaluation of the implications and potential causes of a loss of water
!
from the spent fuel pool.
The review identified several
significant conclusions and p'rovided good recommendations to improv'e procedures and training.
The NSAG report also provided some rough calculations concerning the consequences of a loss of water from the spent fuel pool and discussed the emergency operating procedures.
The only potential failure mode not discussed in the,'SAG report concerned damage due to the impact of dropped objects on the seals The inspector discussed this with the responsible NSAG engineer and determined that a meta'il grating is always in place when the cavity is floode'd and this will adequately protect the seal during transfe'r of heavy objects.
Based on the bulletin response and the NSAG report, the inspector found that the licensee has adequately addressed the concerns of the IE Bulletin and Information Notice.
The corrective actions implemented as a result of the NSAG report will be followed up in a subsequent inspection.
(387/85-26-01)
7.0 TMI Action Plan Re uirements NUREG-0737 At the request of NRC Region I, a review of the status of TMI Actioj Plan requirements was performed by the resident inspectors.
The review of the requirements of NUREG-0737 was necessitated by recent events at an operating PWR plant where it appears that certain plant improvements or modifications that should have been made as a result of NUREG-0737 requirements, were not accomplished adequately or at all.
Attached to this report is the current status and applicable inspection reports 'for the items requiring review by NRC Region I.
The inspector evaluated the present status of installed plant equipnlent or modifications and program/procedure changes to determine if TMI Acti,'on Plan requirements have been met, are in the process of being met, or~
whether additional action is required to resolve the issue.
The inspector also evaluated whether problems have been experienced subsequent to 'the item being closed.
7.1 The following items remain open:
7. 1. 1 I.C. 1 - Short Term Accident and Procedure Review NUREG-0737 requires the use of human factored, functi'on oriented, Emergency Operating Procedures to improve human reliability and the ability to mitigate the consequences of a broad range of initiating events and subsequent multiple failures or operator errors, without the need to diagnose specific events.
l
J
In response to NUREG-0737 Supplement 1 (Generic Letter 82-33) the licensee committed to update their Emergency Operating Procedures and have them implemented by December, 1985 for both units.
The procedure generation package was to be submitted to the NRC by June, 1985.
These commitments were included in a Unit 1 Confirmatory Order, dated June 14, 1984 and the Unit 2 Operating License.
On May 13, 1985 the Emergency Procedures Generation
~Package (PGP)
was submitted to the NRC for review.
The PGP l
provides the basis for the development of plant-spec'ific Emergency Operating Procedures.
The package included a
plant-specific Emergency Procedure Guidelines (EPG) derived from the BWR Owner s Group EPG Revision 3.
The NRC has
'reviewed the BWROG EPG Revision 3 and issued a
SER dated November 23, 1983 'he licensee's submittal contained a
safety analysis of the ten differences between the BWROG EPG and the SSES EPG.
Generic Letter 82-33 requires that the licensee submit a
PGP at least three months prior to the date it plans'to begin formal operator training on the upgraded procedures.
NRC approval of the submittal is not necessary prior to upgrading and implementing the EOP's.
The licensee has already conducted formal training on the EOP's and implemented them.
NRC review of the PGP is currently scheduled to be performed in late 1986.
I.D. 1 - Control Room Desi n Review Item I AD. 1 states that licensees are required to perform a
Detailed Control Room Design Review (DCRDR) to identi.fy and correct human factors design discrepancies.
The objective is to improve the ability of nuclear power plant control room operators to prevent or cope with accidents if they occur by improving the information provided to them.."
The licensee submitted a Program Plan for conducting
,'a DCRDR on June 3,
1982 and a Summary Report was submitted and docketed November 16, 1983.
NRC review of the report resulted in a meeting with the licensee in Bethesda (Parch 12, 1984)
and an on-site pre-implementation audit (October 1-4, 1984).
The NRC SER, dated January 28, 1985 found that the report did not meet all of the requirements of Supplement 1 to NUREG-0737 and guidance contained in NUREG-0700 (i.e. function and task analysis),
and required the licensee to respond to the noted concerns.
In addition, Unit 2 Operating License NPF-22 Section 2.C.( 12)(b) dated March 23, 1984 and Unit 1 Confirmatory Order dated June 14, 1984 required the licensee to submit a
~
~
t
~-
supplemental summary report to the NRC for review a'nd approval which included a proposed schedule for implementation of all human engineering deficiency corrective action by March 1, 1985.
The licensee submitted the Supplemental Summary Report on March 1, 1985 to fulfill the license and confirmato'ry order requirement.
The licensee has proposed to fully implement the corrective action by June 1987.
The NRC staff has scheduled a meeting on August 28, 1985 to discuss the report and the proposed schedule.
NRR is tracking this item and is scheduled to make a decision concerning, the licensee's schedule in September 1985.
II.B.3 - Postaccident Sam lin Ca abilit Item II.B.3 specifies that licensees shall have thel'apability to promptly collect, handle, and analyze post accident samples which are representative of the conditions existing in the reactor coolant and containment atmosphere.
On March 5 - 9, 1984 a special inspection was conducted by NRC Region I to verify and validate the adequacy of ithe licensee's implementation of certain task actions identified in NUREG-0737.
(See Inspection Report 50-387/85-10; 50-388/85-11).
The inspection identified several recommendations for improvement concerning the PASS System.
The licensee has completed corrective aetio'n concerning the recommendations, but the item has not'et been reinspected by NRC Region I.
Item II.B.3 also required a procedure be written based on measurements of radionuclide concentration to provide a
realistic estimate of core damage.
The NRC staff found the licensee's initial procedure, submitted in June 1982',
acceptable on an interim basis, but conditioned bothy,Unit licenses for a revised procedure by the end of the Unit
first refueling outage.
The final procedure was to incorporate hydrogen levels, reactor vessel coolant level, and containment radiation levels in addition to the radionuclide data.
The licensee submitted their revised procedure on November 30, 1984 (PLA-2368), but found it impractical to utilize the containment radiation monitors.
This point is still under evaluation and the licensee.'ubmitted additional information to NRR concerning the procedures on July 31, 198 II. Performance Testin of BWR and PWR Relief and Safet Valves Item II.D. 1 requires licensees to conduct testing to qualify the reactor coolant system relief and safety valves under expected operating conditions for design basis transients and accidents.
Based on review of the licensee's previous submittals, NRC has requested additional information concerning thei, analysis of generic BWR safety-relief valve operability test results.
The submittal date for the information is currently scheduled for September 30, 1985.
II.F. 1 Accident-Monitorin Instrumentation Item II.F. 1-2 requires the provision of a capability'or the collection, transport, and measurement of representative samples of iodine and particulates that may accompany gaseous effluents following an accident.
IIt must be performable without exceeding specified dose limits to the individuals involved.
i, On March
9, 1984 a special inspection was conducted by NRC Region I to verify and validate the adequacy of the licensee's implementation of certain task actions identified in NUREG-0737.
(See Inspection Report 50-387/85-10; 50-388/85-11).
The inspection identified that during an accident situation, high air contamination levels could make the vent stack monitors inaccessible.
The shielding study performed by Bechtel did not consider air contamination from an accident or dose from an unshielded filter.
The licensee performed an evaluation and determined that under a post-LOCA environment, the high radiation levels on the reactor building refueling floor would not permit access to the SPING monitors.
The licensee has committed to install a
new subsystem for post-LOCA conditions.
The new equipment will be independent of the present monitoring systems, except'or the isokinetic probes, and it will be located in a low-radiation area.
The current commitment states that installation and testing of the system will be completed by December 31, 1985
'I.K.3.
17 -
Re ort on Outa es of Emer enc Core Coolin
~Sstems Item II.K.3.17 requires that licensee's submit a report detailing outage dates and lengths of outages for alll',ECCS systems for the last five years of operatio As discussed in SER Supplement 1, the licensee has i,
committed to provide a report summarizing ECCS outage data accumulated during the first five year s of operatio'n.
The data will be based on commercial operation of the units.
7.1.7 7.1.8 III.A.1.2 -
U rade Emer enc Su ort Facilities nit 1 Confirmator Letter dated June
1984 concer U
Y ning emergency response capability and Unit 2 Operating License Section 2.C.(12)(d) require that the Emergency Response Facilities be fully functional no later than June 1987.
Supplement 1 to NUREG-0737 (Generic Letter 82-33) states that the NRC will conduct appraisals of completed Ii facilities to verify that the requirements discussed in the supplement have been satisfied and that the facilities are capable of performing their intended function.
III.A.2 - Lon Term Emer enc Pre aredness Meteorolo ical Instrumentation The licensee has committed in a letter dated Hay 30, 1985 (PLA-2467) to have the upgraded meteorological measurement systems, assessment capabilities, and remote integration capabilities fully operational by the second quarteri of 1986.
SER Supplement 3 states that the NRC staff will cond(et a
post-implementation appraisal of the upgraded capabiIities to ensure adequacy.
7.2 The following action items were determined to have experienced)
problems subsequent to the item being closed:
7.2.1 I.C.6 - Guidance on Procedures For Verif in CorrectI Performance of 0 eratin Activities Item I.C.6 required licensee's procedures to be reviewed and revised, as necessary, to assure that an effectiv'e system of verifying the correct performance of operating activities is provided as a means of reducing human errors and improving the quality of normal operations.
Such", a verification system could include automatic system status monitoring, human verification of operations, maintenance and surveillance activities independent of the people'~
performing the activity.
The licensee stated in their response (FSAR Section 18. 1. 13) that administrative procedure AD-gA-306, "System Status and Equipment Control," provides the means to verify correct performance of surveillance and maintenance
activities.
The status verification utilizes control room indications, operability testing, or independent verification by a second qualified person.
Operating history at Susquehanna has shown that in some cases the administrative procedures and monitoring systems in place were not sufficient to prevent a system from being made inoperable:
.On May 14, 1984 the RCIC system flow controller was not properly realigned for automatic start following a surveillance test Review found that the procedure did not require verification of the step, although it affected system operability.
Additionally, the pump controller is not monitored automatically.
On July 9, 1984 two fuses were incorrectly removed by a construction electrician, disabling one loop of Core Spray and portions of the A D/G, A RHR loop, and HPCI initiation logic circuits.
Although the removal was unauthorized, the power loss was masked to the',
operators due to the design of the Core Spray monitoring circuit.
A human factors analysis on the
"Core Spray Out of Service" switch was performed as part of the licensee's corrective action since 'the installed automatic system status monitoring system did not allow the operators to be alerted to the condition.
On July 26, 1984 Unit 2 experienced a loss of all AC power when four breaker cubicle knife switches were incorrectly opened during a startup test lineup".
The lineup was verified by a test engineer who did not detect the error.
The verifier did not observe the alternate indications available at the local panel, and he had not been trained to the same extent as the operator performing the breaker operations'he licensee commenced a review of their independent verification program following the event.
Based on these events, and previous independent audits, the licensee is currently implementing an Operational Enhancement Program.
Independent verification is an action item of this program.
'.D.2
- Plant Safet Parameter Dis la Console As required by the Unit 2 license condition and Unit 1 Confirmatory Order dated June 14, 1984 the Safety Parameter Display System (SPDS)
was placed in operational status on June 30, 198 To meet the license condition dates, the licensee delayed the installation of the containment isolation valve, position display and did not include it in the principal scope of the initial configuration.
Although the delay of the installation was found acceptable, the implementation of this display is very significant since the design of the Susquehanna control room does not allow for a quick.
evaluation of the status of containment isolation.
Currently, the operator must check the position of
'ndividual valves located on widely separated panels.
The licensee is currently proposing to have this display operational by June 1987.
One other inspector concern has been the requirements for system operability.
Although a license condition required installation, SPDS is not included in the Technical Specifications.
Mhen the system, or portions of the system, become inoperable the licensee normally conducts lengthy discussions to determine what action they should take and what reporting requirements may be applicable.
Discussions with the NRC headquarters duty officers
'ndicate that engineering judgement may be used to determine if the event "results in a major loss of emergency assessment capability".
Although these concerns have not resulted in any actual problems, additional clarification by NRR may be needed in this area.
II. Direct Indication of Relief and Safet -Valve Position Item II.D.3 required relief valves to be provided with a positive indication in the control room derived from a reliable valve-position detection device or a reliable indication of flow in the discharge pipe.
The basic
"
requirement is to provide the operator with unambiguous indication of valve position so that appropriate operator actions can be taken.
At Susquehanna each of the
SRVs is provided with a safety grade TEC Model 144 acoustic monitoring system to detect flow through the valve.
The sensor is mounted on the discharge piping.
In addition tailpipe temperature detectors are also utilized for additional indication'.
Several operational problems have been experienced wi,th the acoustic monitors.
On January 19, 1985 on a Unit 2 scram, the acoustic monitor initially indicated the 'E'RV had lifted but did not indicate for the entire 12 seconds, the valve was open.
On June 28, 1985 the 'C'RV on Unit 2 indicated full open, but no actual lift occurred.
In'oth cases the charging amplifier inside containment was
h I,
replaced.
Inspector review of the licensee SOOR's Inoted eleven occurrences of failures of individual monitors in the last two years.
The majority of the failures h'ave been false open indications of closed valves.
Disucssio'ns with the licensee indicate that the number of failures i'.s con-sistent with industry experience.
Another operational problem with the acoustic monit'ors relates to the Technical Specifications.
The licensee found that two different Technical Specification sections provide two different action statements when an acoustic monitor is declared inoperable.
Technical Specification LCO 3.4.2 "Safety Relief Yalves," states that with one or more SRV acoustic monitors inoperable, restore the
[
inoperable monitor(s) to operable status within 7 days or be in at least Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Technical Specification LCO 3.3.7.5 "Accident Monitoring Instrumentation" states that with the number of operable accident monitoring instrumentation channels less than the minimum channels operable requirements (1 monitor per valve), restore the inoperable channel( s) to operabl,'e status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in least Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The licensee is planning to submit a
technical specification amendment to correct this anomaly.
II.E.4.2 - Containment Isolation De endabilit Item II.E.4.2 requires that containment isolation system designs shall comply with the recommendations of Standard Review Plan (SRP) Section 6.2.4 (i.e., that there be~'j diversity in the parameters sensed for the initiation of containment isolation).
i Licensee and inspector review of the primary containment isolation system has identified numerous discrepancies with drawings, procedures, installations, FSAR tables, and Technical Specifications.
Specific examples include:"
Inspector review of item II.E.4.2 prior to Unit I2 licensing identified errors in the FSAR and TS tables concerning ssolatson signals, penetration configurations and isolation times.
(See 387/84-07-06; 388/84-08-04).
Licensee review identified that a sin le fai lure could g
allow a direct path from the primary containment) to the outside environment through the nitrogen makeup system.
(See CDR 83-00-15 and 387/83-21-06).
Two notices of violation have been issued concerning the controls over manual containment isolation valves.
Both cases involved LLRT valves that were not locked as required.
Although these valves are containment isolation valves in the purest sense they are not included in the FSAR and TS tables.
(See 387/84-14-01 and 388/85-17-01)
.
Licensee review found that the isolation signals to the Core Spray Full Flow Test Yalves were not as specified in the TS and FSAR.
(See 387/84-22-04; 388/84-28-02).
Licensee uncovered discrepancies concerning automatic isolation signals for twenty-one valves during,a review of the Unit 2 Technical Specifications and FSAR.
(See LER 83-130).
The majority of the noted items have been corrected by the licensee, but not all have undergone followup by the inspectors.
II.F. 1.6 - Containment H dro en Monitor Item II.F. 1.6 required a continuous indication of hydrogen concentration in the containment atmosphere to be provided in the control room.
Measurement capability was to be provided over the range of 0 to 10 percent hydrogen i,
concentration under both postive and negative ambient pressure.
The licensee has experienced repeated operational difficulties with the hydrogen/oxygen (H202) analyzers.
(See Inspection Report 50-387/85-01).
At least
Significant Operating Occurrence Reports (SOORs)
and '9 LERs have been issued related to problems with the H202 analyzers.
Operator confidence in the indicated
concentrations has been significantly degraded due to the unreliable operation and common erroneous readings.
Addi-tionally, the IKC technicians have spent an inordinate'mount of time maintaining the analyzers.
Both channels of H202 analyzers are required to be operable by Technical Specifications.
The majority of fai lures have induced the oxygen analyzer position of the sensor which is only used to verify that the containment is inerted (less than 4%
oxygen).
The analyzer manufacturer is COMSIP, Inc.
Problems have been attributed to sample pump mechanical wear and regu-lator failure due to moisture and dirt in the unfi lteI'ed
7.2.6 8.0 Unit 1 License Conditions
sample gas.
The licensee is currently evaluating th'
system operation to improve system reliability.
In January 1984, the licensee reported that COMSIP, !Inc.
had notified Bechtel per
CFR 21 that a potential problem existed with the standard H2 and 02 catalyst bed used in the K-1V Gas Monitor.
The report stated that degradation of the catalyst due to iodine concentrations in containment post LOCA may cause lower than actual indications.
The catalyst was replaced with a modified type supplied by the vendor.
Although the iodine poisoning problem was corrected, the new catalyst requires significantly more time (approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) for the hydrogen readings to stabilize after placing the unit in service.
II.K.3.18 Modification of Automatic De ressurization In response to Item II.K.3.18 the licensee modified the ADS logic to bypass the high drywell pressure portion of, the actuation logic after a specific time interval and added a
manual inhibit switch.
In June 1984 the inspector determined that the Technical Specifications did not permit surveillance testing of, the ADS system without entering an Action Statement which requires plant shutdown.
In addition, the Technical'pecifications reflected an incorrect number of minimum operable channels per trip system for the drywell bypass timer.
The Technical Specification has been amended
~to allow placing a channel in an inoperable status for up to two hours to permit testing.
A discrepancy still exi'sts in that the Technical Specification permits no out-of-service time if one channel is lost.
This is much more restr'ictive than the Technical Specification for other ECCS logic systems and the licensee intends to pursue obtaining ~relief from the Technical Specifications at a later date
~
8. 1 LC 2.C.
Emer enc Diesel En ine Star tin S stems Unit 1 Facjlity Operating License NPF-14 Section 2.C(27) stated,'hat prior to startup following the first refueling outage the licensee shall install air dryers upstream of the air receivers for the
"
FSAR Question 040.90 and Section 9.6 '.4 of the Susquehanna Safety Evaluation Report (NUREG-0776) states that operating experience, has shown that accumulation of water in the starting air system has, been one of the most frequent causes of diesel engine failure to start on
, I V
r
demand.
Condensation of entrained moisture in compressed air lines leading to control and starting air valves, air start motors, and condensation of moisture on the working surfaces of these components has caused rust, scale and water itself to build up and jam the internal working parts of these vital components thereby preventing or delaying starting of the diesel generators.
In an effort toward improving diesel engine starting reliability, the NRC required that the licensee's compressed air starting system design include air dryer s for the removal of entrained moisture.
As discussed in Inspection Report 50-387/85-01; 50-388/85-01, numerous diesel generator failed starts due to slow start times at Susquehanna have been attributed to sluggish operation of pneumatic control valves.
Disassembly of the pneumatic valves has shown evidence of corrosion, apparently caused by moisture in the control air lines.
During the Unit 1 first refueling outage, as discussed in Inspection Report 50-387/85-18; 50-388/85-16, the licensee installed two air dryer assemblies on each diesel generator air start system.
The licensee reported the completion of the air dryer modificationl'o the NRC in a letter dated June 13, 1985 (PLA-2479).
Subsequent to the first refueling outage, the licensee has had operational difficulties with the air dryers and compressed air-receiver tra'ins.
It appears that the differential pressure caused by the air flow through the air dryers was not adequately accounted for in the design of the modification, and the relief valves on the compressors are lifting repeatedly during normal,,system operation.
The compressors automatically cycle to maintain air pressure in the receivers between 245 255 psig.
The relief valve on the compressor discharge has a setpoint of 265 psig.
During system operation, if the differential pressure across the air dryers exceeds 10 psig, the relief valves liftwhile attempting to recharge the receiver.
The relief valve setpoint cannot be increased since the current compressors are already operating at their maximum 'design limit.
The licensee has performed an investigation of the system operation and determined that a modification is required to increase the, size of the compressor s.
An urgent modification request has been submitted and new compressors have been ordered.
Until the modification is complete, the air dryers have been valved out of the system to prevent damage to the relief valves.
The inspector will review the licensee's corrective action in a
subsequent inspection (387/85-26-02).
~
~
I
9.0 Onsite Review of Pro osed Chan es to Technical S ecifications Related to 5th Diesel Installations By letter dated December 21, 1984, the licensee had proposed changes to Technical Specifications 3.7. 1.2 and 3.8. 1. 1.
The changes were proposed on a one time basis to allow the licensee to remove the four existing diesel generators (A, B, C,
and D), one at a time, from service for, an accumulated time of 60 days.
The changes are required in order to perform work on the connection of power and control circuits to the new fifth diesel generator (E) being installed at the station.
An onsite review of the proposed changes and the related licensee submittals were conducted by Region I staff on August 19-23, 1985 in the following areas:
Technical justification of the changes Reliability of Offsite Power System Reliability of installed diesel generators Work performed under Limiting Conditions for Operation (LCO)
Emergency procedure and operator training A review of the licensee'
submittal on the Probabi listic Risk Analysis (PRA) studies related to the changes is being performed by the Office of NRR.
As of the date of this inspection report, the review of the proposed changes, including the PRA studies, is still in progress'fter the review is complete, the results of the review will be documented in ~a Safety Evaluation Report (SER) which will be issued by NRR.
No violations or deviations were identified during the onsite review.
O.D ~Ki M
On August 30, 1985 the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of thi s report and discussions held with licensee representatives, it was determined that this report does not contain information subject to
CFR 2.790 restriction ATTACHMENT 1 TMI ACTION PLAN ITEM STATUS TMI ACTION ITEM TITLE STATUS INSPECTION REPORT UNIT 1 UNIT 2
.,
SER Shift technical advisor Closed 82-11 83-07 I.A.1.2 Shift supervisor res onsibilities Closed 82-19 83-07
0 I.A.1.3 I.A.2. 1 Shift mannin Immediate upgrade of RO & SRO training and ualifications Closed Closed 82-19 82-11 83-07 83-14
I.A.2.3 I.A.3.1 Administration of trainin ro rams Closed Revise scope
&
criteria for licensin exams Closed 82-11 82-11 NA
0 1.8.1.2 Evaluation of organization
&
mana ement Closed 82-28 83-07 Short-term accident
&
rocedure review 0 en 82-19 83-14
0 Shift & Relief turnover rocedures Shift supervisor res onsibilit Control-room access Feedback of operating ex erience Closed Cl osed Closed Cl osed 82-11 82-19 82-19 82-11 82-11 82-19 83-07 83-07 83-07 83-07
0
~ ~
II PL'l yl
~ '"
Attachment
TMI ACTION ITEM TITLE STATUS INSPECTION REPORT UNIT 1 UNIT 2 SER I.C.6 I.C.7 Verify correct performance of operating activities NSS vendor review of rocedures Closed Closed 82"19 82-33 82-20 82-33 83-21 83-14 1 0
1 0 I.C.8 Pilot mon of selected emergency roc for NTOLs Closed 82-19 83-14
0 I.D.1 Control-room desi n reviews 0 en 82-17 82-19 82-33 84-08 84-22 6,5,
'4
0 I.D.2 Plant-safety-parameter dis la console Closed 84-34 84-41 I.G.1 II.B.1 II.B.2 II.B.3 II.B.4 II.D.1 II.D.3 Training during low-,power testin Reactor-coolant-s stem vents Plant shieldin Postaccident sam 1 in Training for mitigating core dama e
Relief 5 safety-valve test re ui rements Valve position indication Closed Closed Closed 0 en Closed 0 en Cl osed 82-33 82-11 82-33 82-19 84-10 82-11 82-17 82-11 82-19 85-12 83-14 83-14 83-14 84-11 83-21 NA 83-14 6,
i,,3
0
1 0
,3
0 3 0 1 0
0 II.ED 4.1 Dedicated hydro-en 'netrations Closed 82-11 83-14
!r le h
I
~4
TMI ACTION ITEM TITLE STATUS Attachment
INSPECTION REPORT UNIT 1 UNIT 2 SER II. E.4.2 Containment isolation de endabilit Closed 82-19 84-08 6,4,
- 310 II.F.1 Accident-monitoring instrumentation 0 en 82-33 84-10 84-11 84-24
- 510 II.F.2 II.K.1.5 II.K.1.10 II. K. 1. 22 II.K.1.23 II.K.3.3 II.K.3'3 II. K.3. 15 II. K.3. 16 II.K.3.17 II.K.3.18 II ~ K.3. 21 II.K.3.22 Instrumentation for detection of inadequate core-coolin Review ESF valves Operability status Aux heat rem s stem roc RV level roc Reporting SV &
RV failures
&
challen es HPCI & RCIC init levels Isolation of HPCI and RCIC Challenges to
& failure of relief valves ECCS outa es AOS actuation Restart of LPCS
& LPCI RCIC suction Closed Closed Closed Cl osed Closed Closed Closed Closed Closed 0 en Closed Closed Closed 82-17 82-19 82-19 82-11 82-19 82-19 82-19 82-19 82-11 82-11 82-19 85-18 82-11 82-19 83-21 84-08 83-21 83-14 83-24 83-14 83-21 83-14 NA 84-16 85-16 83-24 83-14
, 6,4,3
0
0
0
0
1 0
0
0
0 6,3
1
1
1
~
Attachment
TMI ACTION ITEM TITLE STATUS INSPECTION REPORT UNIT 1 UNIT 2 SER II'.3.24 II.K.3.25 II.K.3.27 II.K.3.28 II.K.3.30 II.K.3'1 II.K.3.44 II.K.3. 45 II.K.3.46 Space cooling for HPCI/RCIC Power on pump seals Common reference level Qual of ADS accumulators SB LOCA methods Plant-specific anal sis Evaluate tran-sients with sin le failure Manual depressuri-zation Michelson con-cerns Closed Closed Closed Closed Closed Cl osed Closed Cl osed Closed 82-11 84-18 82-19 82-17 82-17 82-33 82-11 82-11 82-11
'83-14 83-14 84-22 83-21 83-32 84-08 NA NA 1 0 610
,2
0 3 0
0 1 0
III.A.1.1 Emergency prepared-ness short term Closed 82-11
210 III.A~ 1
~ 2 III.A.2 III.D.1.1 III.D.3.3 III.D.3.4 Upgrade emergency support facilities Emergency re aredness Primary coolant outside con-tainment Inplant I2 radiation monitorin Control-room habitabi lit 0 en 0 en Cl osed Cl osed Cl osed 82-11 82-11 82-33 82-33 84-10 82-11 83-32 83-32 84-11 210
210
0
r s.I J