IR 05000387/1984026
| ML17139C713 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/06/1984 |
| From: | Jacobs R, Nicholas H, Plisco L, Stronsnider J, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17139C712 | List: |
| References | |
| 50-387-84-26, 50-388-84-33, NUDOCS 8411290423 | |
| Download: ML17139C713 (55) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/84-26; 50-388/84-33
tl
.
58->>
AT 8; ~88 AT 52 License Nos.
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 Conduct d:
Jul 16 - Se tember
1984 Inspectors:
H.
aco s, Senior Resident Inspector
.
R. Plisco, Resident Inspector H. Nicholas, Lead Reactor Engineer date ii/~t~~
date I/K yff date Approved by:
ck Strosnider, Chief Reactor Projects Section 1C, DPRP date Ins ection Summar
Areas Ins ected:
Routine resident inspection (Ul 115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br />, U2 181 hours0.00209 days <br />0.0503 hours <br />2.992725e-4 weeks <br />6.88705e-5 months <br />)
of plant operations, ESF system operability, licensee events, open items, main-tenance, startup testing, survei llances, and preoperational test program.
Results:
Unit 2 core spray system walkdown identified minor procedural discrep-
~ancies Detail 2.3); Unit 2 coT'e spray surveillance program is satisfactory (Detail 5.3);
ECCS maintenance review determined that repetitive failures are evaluated for root cause and that effects on redundant components are considered (Detail 5.2.2).
No violations were identified.
aiiiV90ai3 Seli09 PDR ADQCK 05000387
l 7>
DETAILS 1.0 Fol 1 owu on Previous Ins ection Items Closed Ins ector Followu Item 387/82-09-08
A roval of Vendor Manuals The inspector reviewed Nuclear Department Instruction NDI-QA-15.3. 10, Revision 0, Installation Operating Manual ( IOM) Use and Control, which describes the practices, requirements, and responsibilities associated with the use, review, approval, revision and control of vendor manuals.
The procedure was approved June 1,
1984.
The instruction adequately controls the use of the IOM's by the licensee.
1.2 Closed Unresolved Item 387/82-37-01:
LLRT Re uirement for Penetration X-218 Incorrect in the FSAR In a previous inspection, the inspector noted that the local leak rate test (LLRT) for containment penetration X-218, Instrument Gas Supply, was required to test outboard solenoid valve SV-12671 and outboard check valve 1-26-164 as stated in FSAR Table 6.2-12.
This was contray to Technical Specification Table 3.6.3-1, in which valve SV-12671 and inboard check valve 1-26-070 were specified for the typg.",
C primary containment isolation valve leakage rate tests.
The licensee actually tested all three valves, and all met the acceptance~-.
criteria.
On May 29, 1984, the licensee requested an exemption to
CFR 50 Appendix A, General Design Criteria (GDC) 56 for the Instrument Gas Penetration (X-218).
The original design for containment isolation valves for the one inch instrument gas penetration was to have a check valve (1-26-070) inside containment and a globe valve (SV-12671)
outside containment.
However, the check valve inside containment is subject to severe environmental conditions such as suppression pool dynamic loads and the licensee therefore did not want to rely on this valve to provide the isolation function.
In order to accommodate isolation, a check valve (1-26-164)
was added outside containment between the penetration and the globe valve.
The new arrangement does not meet the requirements of GDC 56, which does not allow the use of a simple check valve.
However, it does meet one of the alter-native acceptance criteria specified in Section 6.2.4 of the Standard Review Plan.
The remainder of the corrective action, including the necessary FSAR revision, will be followed under open item 387/84-07-06.
1.3 Closed Ins ector Followu Item 388/83-32-04
- Nuclear Instrument Movements without Secondar Containment Inte rit During the Unit 1/Unit 2 tie-in outage in January 1984, the licenseee was unable to comply with Technical Specifications (TS) on Unit 1 due to the need to perform weekly survei llances on the Source Range Monitors
I
<1-f
(SRMs)
and Intermediate Range Montors (IRMs) while secondary containment integrity was not established.
Specifically, Technical Specification 3.6.5. 1 and 3.6.5.3 require establishing secondary containment integrity when performing core alterations, and SRM and IRM movements fall within the definition of core alterations per Technical Specification 1.7.
The Unit 2 Technical Specifications, as issued, were corrected to exclude nuclear instrument movements from the definition of core alterations.
By letter dated May 18, 1984, the licensee submitted proposed Amendment 43 to the Unit 1 Technical Specifications to also change the definition of core alterations to exclude nuclear instrument".:
movements.
Closed Ins ector Followu Item 387/82-45-01:
Safet Relief Valve Tail i e
Tem erature Alarm Following safety relief valve (SRV) testing on Unit 1 in Jaunary 1983, several SRVs had minor leakage which caused their tailpipe temperature to stay above 200'
which was.the alarm setpoint.
Since this alarm would not reflash if other SRVs began leaking, GE and the licensee determined that SRV leakage which would cause tailpipe temperatures up to 250 F was acceptable and hence, it was desirable to revise the alarm setpoint to 250 F.
By work Authorization S36987, the alarm setpoint for temperature recorder B21-1R614, which monitors SRV tai 1-pipe temperatures, was revised to 250'.
The inspector also verified that the Setpoint Index and Alarm Response procedure AR-110-001 had been revised to reflect the new setpoint.
Closed Licensee Identified Item 387/82-40-06
HPCI Steam Line Sensor s Found Out of Tolerance On November 10, 1982, the licensee reported in LER 82-036 that both HPCI steam line sensors (PDIS-E41-N004 and PDIS-E41-N005),
which are utilized to detect line breaks, were found out of tolerance when the quarterly surveillance was performed on October 27, 1982.
The licensee adjusted the surveillance frequency to monthly.
The surveillance was performed successfully on November 23, 1982, but on December 17, 1982 one instrument (PDIS-E41-N005)
again exceeded the allowable setpoint.
This recurrence was reported in LER 82-077.
After this second instance of instrument drift, the licensee revised the instrument setpoints and the final tolerances in the surveillance procedure to more accurately reflect the instrument performance capability.
The instrument setpoints were adjusted in the conservative direction to provide margin for instrument drift and thereby avoid exceeding the allowable setpoint.
The calibrations performed since the procedure revision have met the acceptance criteria and the calibrations continue to be performed on a monthly basi I I 'I T
Four other LERs were submitted in 1983 describing similar drifting problems in Barton 288A differential pressure instruments (See Inspec-tion Report 50-387/84-07; 50-388/84-08).
The licensee has initiated a study to determine the deviation from the setpoint necessary to ensure a high probability that instrument drift between surveillances would not cause the setpoint to drift outside the allowable band.
The inspector reviewed the survei llances performed in June and July 1984, and both met the acceptance criteria.
1.6 Closed Unresolved Item 388/83-04-01
- Discre ancies with FSAR Section 6 and
Item Descri tion:
All testing completed successfully, awaiting FSAR>>
change submittal and approval for section 1 and 14.
1.7 Ins ector Activities:
The inspector verified that the FSAR changes'=:
included the addition of note 21 to Table 6.2-22; the determination
!,-
by the licensee that the previously assumed water seal at the feedwater., "
containment isolation valves is unlikely to exist for 30 days followingq.
the Design Basis LOCA; and, that section 14 was updated to reflect the Unit 2 test program.
Closed Unresolved Item 388/84-23-01
- Unit 2 Preo erational Test
',.
~Exce tions Item Descri tion:
Test exceptions for completed tests to be resolved, and approved by established priority code definitions.
1.8 Ins ector Activities:
The inspector verified that these completed preoperational and acceptance test exceptions were resolved or dispo-sitioned by the plant staff nonconformance report (NCR) program.
Closed Unresolved Item 388/84-23-02
- Unit 2 Preo erational Test Exceptions Item Descri tion:
Incomplete tests to be completed by established priority code definitions.
Ins ector Activities:
The inspector verified that these incomplete preoperational and acceptance test exceptions were resolved or dispositioned by the plant staff nonconformance report (NCR) program.
1.9 Closed Unresolved Item 388/84-23-03
- Unit 1 Preo erational Test
~Exce tions Item Descr i tion:
Test exceptions for completed tests of Unit 1 to be resolved and approved by first refueling outag P
Ins ector Activities:
The inspector verified that these completed preoperational and acceptance test exceptions were dispositioned by the plant staff nonconformance report (NCR) program.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room area daily to verify proper manning, access control, adherence to approved procedures, and compli-ance 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 examined.
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, badging and availability of radiation monitoring equipment.
The inspector reviewed shift supervisor and plant control operator logs covering the entire inspection period.
Sampling reviews were made of tagging requests, night orders, shift turnover sheets, the bypass log, incident reports, and gA nonconformance reports.
The inspector also observed several shift turnovers during the period.
No unacceptable conditions were identified.
2.2 Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, penetration areas, reactor and turbine buildings, r adwaste building, ESSW pumphouse, Circulating Water Pumphouse, Security Control Center, diesel generator building, plant perimeter and containment.
During these tours, observations were made relative to equipment condition, fire hazards, fire protec-tion, 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.
2.3 ESF S stem Walkdown On August 23, 1984 the inspector independently verified the operabil-ity of the Unit 2 Core Spray System by performing a complete walkdown of the accessible portions of the system.
The engineered safety system status verification included the following:
'4t
'4
"M
Confirmation that the licensee's system check-off list and opera-ting procedure are consistent with the plant drawings and as-built drawings and as-built configuration, Identification of equipment conditions and items that might degrade performance, Inspection of breaker and instrumentation cabinet interiors, Verification of properly valved in and functioning instrumentation";
Verification that valves were in proper position, power was available, and appropriate valves were locked.
The following references were utilized during this review:
Operating Procedure OP-251-00, Revision 1,
Core Spray System, dated April 9, 1984 Bechtel Drawing, M-2152, Revision 10, Core Spray GE Elementary Diagram, M1-E21-20, Core Spray System Bechtel Schematic Diagram E-156, Sheet 5, Revision 14, Core Spray Pump 2A GE Operation and Maintenance Instructions GEK-73609B, Core Spray System FSAR Section 6.3 PP5L Design Description Manual, Chapter ll Technical Specifications The inspector determined that the system was properly aligned in accordance with the operating procedure and the equipment conditions indicated the components were well maintained.
The following minor items were identified:
The condensate transfer system
"Keep fill"station valve procedure lineup does not match the system diagram M-.2152.
Drawing Change Notice (DCN)84-875 was issued on April 25, 1984 to alter the original lineup, but the lineup on the DCN is not consistent with the normal valve positions in the operating procedure.
The system will function properly with either lineup, but the docu-ments require review for consistenc tg C
Several LLRT valves are required to be capped in accordance with drawing M-2152, but the lineup in the operating procedure does not require it to be capped.
During the walkdown the inspector verified that the valves (i.e.,
252036 and 252038)
are actually capped.
Two valves were found to have small packing leaks, 252F004B (Cor e-..
Spray Loop B outboard injection valves)
and 252F020D (Core Spray Pump D discharge check bypass valves).
The licensee stated that; Work Authorizations (WA) would be written to initiate corrective'aintenance.
Some of the component identifications in the operating procedure~'re not consistent with the nametags in the field and could lead"."
to some confusion for the operators performing the lineup.
Additionally some of the labels on the instrument rack root valvesk'-
are incorrect.
For example, drain valve DV1FT2N003B/FIS2N006B-is incorrectly labeled FT2N006B/FIS2N006B; and several drain valves have the identical nametag.
The instrument root valves to the Core Spray Sparger Break Detection Instrumentation, a differential pressure indicating switch (E21-DIS-2N004A,B)
used to confirm the integrity of the core spray piping within the reactor vessel, were not included
-'n the system lineup checkoff lists.
The valves were in the proper position.
The licensee is implementing a program to include all process instrumentation root valves and rack valves in either the operating or 18C procedures, but the program has not yet been completed.
The inspector identified the procedural deficiencies to the licensee.
The licensee stated the procedures would be revised to include the missing valves and ensure the procedure correctly reflects the as-built condition.
The corrective actions for the above items will be followed up on a subsequent inspection.
(388/84-33-01)
3.0 Summar of 0 eratin Events 3.1 Unit
On July 15 at 9: 15 a.m. Unit 1 scrammed from 100% power when a phase-to-phase fault in the transmission line between the generator output breaker and the 230 KY switchyard caused a generator load reject.
A subsequent inspection found that a tree had grown close enough to the transmission line to cause an arc.
The trees were trimmed and the unit returned to operation on July 1,I A
p h
J r,
t,/
'I I
On July 16 at 6:08 p.m., the unit scrammed on a loss of condenser vacuum when the low pressure (C) condenser vacuum breaker was inadvertently opened by a turbine building operator.
The unit returned to operation on July 17.
On July 18 at 5: 14 a.m.,
the unit scrammed on loss of condenser vacuum
'hen an incorrect valve was operated due to an unclear valve number on a piping drawing.
The valve manipulation vented the condenser to the air space of the Condensate Storage Tank.
The unit returned to operation on July 19 and operated at or near 100% power for the remainder of the inspection period.
3.2 On September 12, Unit 1 commenced a power reduction in preparation for plant shutdown due to two inoperable diesel generators (D/Gs).
Following restoration of the 'D'/G at 8:45 p.m.
September 12, the unit returned to 100% power.
(See Detail 5.2. 1).
Unit 2
~
~
~
On July 15 at 10:10 a.m. Unit 2 scrammed from 25% power due to the loss of main condenser vacuum.
The loss=of vacuum was caused by the isolation of the common off gas recombiner and appeared to be related='o the Unit 1 scram and subsequent voltage transient which occurred an hour before (See Detail 3. 1).
The unit returned to operation on July 17 and continued with test plateau 2.
On July 26, at 1:37 a.m., with the unit operating at 30% power, the Loss of Turbine Generator and Off-Site Power startup test (ST-31. 1)
was initiated by opening the Unit 2 generator output breakers and the Bus 20 feeder breaker.
This resulted in a reactor scram due to turbine control valve fast closure and deenergization of the Unit 2 4KV ESS busses, which had their alternate feeder breakers racked out for the test.
During the transient, the four emergency diesel generators failed to start automatically as designed because of an improper switch alignment.
AC power was restored from the offsite supply approximately eleven minutes after the scram.
The event was investigated by NRC Region I and reported in Special Inspection Report 50-388/84-34.
On August 1 at 10: 15 p.m., the unit reached criticality and continued with test plateau 2.
On August 7 at 5:03 a.m., with the unit operating at 30% power, the Loss of Turbine-Generator and Off-Site Power startup test (ST 31. 1)
was reperformed successfully.
(See Detail 6. 1.2).
All safety systems functioned properly without manual assistance.
This test marked the completion of Test Condition l'r
On August 8 at 6:50 p.m., the unit reached criticality and commenced Test Condition 3.
On August 10 and August 13, steam leaks were discovered in the high pressure inlet to the turbine generator at several flange connections..
On both occasions the turbine was shutdown and the main steam stops were closed to perform the necessary repairs.
On August 26 at 12:32 a.m., during weekly surveillance testing of No.
4 Combined Intermediate Valve (CIV), a high level condition occurred in the "B" moisture separator drain tank resulting in a main turbine trip, which caused a reactor scram from 43% power.
The unit returned to operation the same day.
(See Oetai 1 3.3).
On August 28 at 1:51 p.m., the reactor scrammed due to a turbine trip; which was caused by a high level in the 'B'oisture separator drain tank.
At the time of the scram, the licensee was performing CIV testing at 45% power.
The testing was being conducted at various power levels to gather data as a follow-up to tAe August 26 scram, and" all testing up to 40% had not caused any drain tank level oscillations.".
(See Oetai 1 3.3).
On September 2 at 7:43 p.m.,
the unit reached criticality to continue:
troubleshooting the drain tank level osci llations and continue with the startup test program.
No additional problems were encountered with drain tank level during the startup.
On September 8 at 3:45 p.m.,
the unit scrammed from 50% power while performing a weekly test of the EHC load imbalance circuit.
The reactor scram was caused by turbine control valve (TCV) fast closure caused by 40% mismatch between turbine crossaround pressure and gener-ator output.
The cause of the mismatch was a faulty crossaround pressure transmitter which was recalibrated.
The reactor was restarted later that day, achieved criticality at 7:46 p.m.,
September 8 and continued with startup testing.
3.3 Unit 2 Reactor Scrams on Au ust 26 and
1984 On August 26 at 12:32 a.m., during weekly surveillance testing of Combined Intermediate Valves (CIV), Unit 2 scrammed from 43% power.
The scram was due to turbine control valve fast closure which was caused by a turbine trip due to high level in the 'B'oisture Separator (MS) drain tank.
The licensee conducted testing of the control valves which drain the tank to the No.
No problems were found.
The licensee decided to return to operation and conduct additional testing of the MS at power levels below 24%
(i.e.
below this power level, turbine control valve fast closure scram is bypassed).
At 8:28 p.m.
on August 26, the reactor was taken critical and the turbine generator was synchronized with the grid at 5:06 a.m.
on August 27.
The licensee began conducting testing of all turbine stop valves, control valves, CIV valves and turbine bypass valves while monitoring various parameters associated with the MS drain tanks.
No problems were observed at testing below 25% power, so the licensee elected to continue valve testing at 5% power increments up to 50%
power.
The inspector observed valve testing at 40% power.
Operation of CIV valves caused no significant change in MS drain tank level or MS pressure.
Operation of turbine bypass valves did cause drain tank.
level to oscillate between 0 and 30 inches although this may have been due to reference leg flashing and not actual level change.
The turbine trip on high level is set at 70 inches on two or three float switches which would not be affected by flashing.
The licensee increased power to 45% and continued valve testing.
At-1:51 p.m.
on August 28, the reactor scrammed due to a turbine trip caused by high level in the 'B'S drain tank+ At the time of the scram, the licensee was testing No.
4 CIV, and Had finished testing
'he stop valves and Nos.
1, 2 and 3 CIVs with no significant effects
.
on MS parameters.
All systems functioned properly on the scram and the licensee remained in Operational Condition 3, Hot Shutdown, to continue testing of the MS.
Between August 29 and 31, the licensee conducted extensive testing oi" the 'A'nd 'B'S drain tank and level control system in accordance with TP-293-002.
The testing consisted of filling and 'draining the MS drain tanks with demineralized water and observing operation of the level control valves, emergency dump valves (12 inch valves which dump to the condenser when tank level reaches a high level) and level transmitters, while monitoring actual level with temporary instrumen-tation.
The test results did not identify the cause of the high level trips on August 26 and 28.
The licensee also opened and inspected the 'A'nd 'B'S and associated drain tanks and found no problems.
On September 1, the licensee noticed some insulation damage and conducted an inspection of one of three 42 inch crossaround pipes between the HP turbine exhaust and the 'A'S.
The piping was dis-placed approximately 2 inches and one hanger, H17, had a failed spring can.
The licensee determined that drain valve HV-20151A1 for this pipe would not operate and found a large amount of water in the pipe (thousands of gallons).
When the water was drained the pipe returned to its original location.
The licensee repaired H17 and inspected all other hangers on the pipe for damage.
None was found.
The licen-see also visually inspected the pipe welds where the pipe is connected to the MS and HP turbine.
No damage was discovere At 7:43 p.m.
on September 2, the reactor was taken critical and power was increased while CIV testing continued at 5% power increments.
No problems were encountered even when testing was conducted at 44%
48%
and 50% power.
Hence, the MS drain tank high level problem appears to be related to the water which was found in the crossaround pipe although the precise mechanism that caused the water to get into the
'B'S and fill the drain tank is not known.
The inspector reviewed the sequence of events printout and GETARs printouts for both scrams.
In addition, the inspector witnessed some of the valve testing.
No discrepancies were noted with the valve testing.
On the sequence of events printout, the inspector noted that no Division 2 manual scram signal appeared on the printout although a Division 1 signal did.
The operator is required by the reactor scram procedure EO-200-001 to manually scram the reactor following an automatic scram.
The licensee determined that the Division 2 manual scram signal had been inadvertently deleted from the sequence of events printout.
The licensee corrected this discrepancy.
4.0 Licensee Re orts 4. 1 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 accuracy of the description of -the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
84-028/00, Reactor Scram due to Transformer T-10 Deenergization
- 84-029/00, Reactor Scram due to Transformer T-10 Deenergization 84-030/00, Boron/Sodium Pentaborate Parameters Out of Specification 84-031/00, HPCI Inoperable Due to Discharge Check Valve Not Sealing
"84-032/00, Fire Protection Detector Survei llances not performed
t I
+t N
Ir
84-033/00, Reactor Scram Due to Low Condensate Vacuum I
84-034/00, Unit 1 Reactor Scram 'on Transmission Line fault and Subse-quent Unit 2 Scram on Loss of Condenser Vacuum 84-035/00, Reactor Scram Due to Turbine Trip on Loss of Vacuum 84-037/00, EPA Breaker Trips Caused ESF Actuations Unit 2
~"84-010/00, HPCI Startup Suction Strainer left in system after completion of preoperational.test program.
84-011/00, Four Spurious ESF Actuations (SBGT and CREOASS)
- 84-012/00, Core Spray Isolation Logic Modification
"~*84-013/00, Loss of Offsite Power to Unit 2 84-014/00, Reactor Water Cleanup Isolation due to high room temperature 84-015/00, Reactor Water Cleanup Isolation due to Instrument Drift
- Previously discussed in Inspection Report 50-387/84-22; 50-388/84-28.
~*Further discussed in Detail 4.2.
- Further discussed in Special Inspection Report 50-388/83-34.
4.2 Onsite Followu of Licensee Event Re orts 4.2. 1 LER 84-010/00 HPCI Startu Suction Strainer Unit 2 On June 27, 1984, a
16 psi pressure drop in the Unit 2 HPCI pump suction piping was noted during the test data review conducted as part of the Heatup Phase Plateau Review.
The test data review indicated that the required HPCI pump net positive suction head (NPSH) of greater than 21 feet was not achieved.
The calculated NPSH was actually 19 feet.
The reason for the reduced NPSH was found to be startup strainer blockage from particulate matter in the booster pump suction piping.
The strainer had been purposely left in the system after the preoperational test program was complete, since full system flow could not be achieved until nuclear steam was available, but it was not adequately tracked during the system turnover proces hi
'I dtt V
A
During the startup testing, the discharge pressure and flow rates were within the Technical Specification surveillance requirements.
On June 27 the HPCI system was declared inoperable for approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> to facilitate the removal of the startup strainer.
The strainer, which had split at its seam, was removed'n June 28 and a ring spacer was installed..
The system was then returned to operable status.
The licensee performed a walkdown of Unit 1 and Unit 2 systems~
containing startup strainers to determine the extent of the problem.
Seven other strainers were found installed, and 34 had an unknown status due to inaccessibility or by being covered by insulation.
Twenty other strainers had been removed, but the proper ring spacer had not been installed.
Work Authorizations were written to inspect and remove the strainers
.for those strainers in which the previous removal could not be verified. Engineering Work Requests (EWR) were written to evaluate the stress on the piping systems in which the ring spacers were not installed.
The startup strainers that currently remain in other systems do not affect any Technical Specification requirement nor have any significant effect on system performance.
Inspector review of this LER found that the cause for the reportable occurrence was not adequately discussed; i.e.,
the reason why the strainer remained in the system after preoperational testing was completed.
The inspector discussed the LER concerns with licensee representatives and the licensee stated a supplementary report would be submitted.
This item remains unresolved pending further review of the licensee's corrective action and supplemental LER.
(388/84-33-02)
LER 84-012 Core S ra Lo ic Modification Unit 2 During the installation of a modification to the Unit 2 Core Spray isolation logic on July 9, 1984, two control power fuses to the Division I Core Spray logic were incor-rectly removed by a construction electrician:
Removal of these fuses not only disabled Division I of Core Spray, but also affected other safety system J I
Plant Modification Request (PMR) 84-3086 was issued to cor-rect the isolation signal to the Core Spray (CS) full flow test valves, since the installed isolation signal was not consistent with the Technical Specification (See Unit
LER 84-026 dated June 14, 1984).
Construction Work Order (CWO)
40401 was written to implement the PMR, and was reviewed by the applicable work group.
Step 2. 1 of the work plan stated that "Before starting work, assure proper blocking has been provided".
(For example....remove control fuses F1A/F2A in 2C626...)
At approximately 10:00 a.m.
on July 9 the two CS logic control fuses (F1A/F2A) were removed by the electricians~:
As noted above, the fuses were mentioned in the CWO as a
possible blocking point for personnel protection, but another acceptable blocking method had already been provided.
The electricans construed the procedure to delineate the fuses as a local blocking point.
The fuses were not mentioned in the Equipment Release Form (ERF), which tracks equipment taken out of service, since other suitable blocking was identified.
Therefore, operations personnel did not authorize:
the fuse removal, nor were they aware that the fuses would be pulled.
1.
Division I of the Core Spray System - Division I CS logic would not have provided an initiation signal to the "A" and "C" CS pumps and the injection valve.
2.
"A" Diesel Generator the "A" diesel generator would not have received an initiation signal from the Division I
CS logic to start on a Unit 2 LOCA. (It would have started on a loss of offsite power signal from either Unit and closed onto the dead bus.)
3.
Division I of RHR System - the A and C channels for the reactor vessel low level and the reactor vessel low pressure instrumentation were inoperable.
However, the system should have operated properly, if needed, due to the redundant initiation logic.
4.
HPCI System the A and C channels for the reactor vessel low level and the high drywell pressure instru-mentation were inoperable.
However, the system should have operated properly, if needed, due to redundant initiation logic.
5.
4. 16KV ESS Busses A and C - the degraded bus voltage (less than 84 percent)
load shedding logic would not have received a
LOCA signal to alter the time delay sequence.
6.
Division I of drywell cooling fans would not have tripped during a Unit 2 LOC I J
+ 't
7.
ESW Pump A would not have received the start timer reset, therefore a potential would exist for RHR Pump A and ESW Pump A to start simultaneously during a
LOOP/
LOCA, thereby providing the potential for a diesel generator overload.
8.
Instrument Air Compressors would not have tripped on a Unit 2 LOCA.
9.
Containment Instrument Gas Compressor would not have:
tripped on a Unit 2 LOCA.
10.
Drywell Cooling - a half isolation trip was received.',
When the fuses were pulled, operations personnel received
",.-
indication in the control room of a half-drywell isolation,
'small green light).
They immediately contacted the station".-
work coordination group to determineyif any work had been released which could have caused the Aalf-isolation.
Operations personnel began an investigation of the work involved with the PMR.
The physical work on the PMR was completed by the time the workers were located.
The fuses-.
were reinstalled,. which cleared the half-isolation and restored all other systems at approximately 2:30 p.m.
on July 9.
The actual fuse pulling event was partially masked from the operators by an unrelated instrument AC panel breaker trip at 9:30 a.m.
on July 9 that caused numerous alarms, instru-ment failures, control system failures and reactor water cleanup pump trips.
The breaker trip resulted in a loss of power to the feedwater level control system, which in turn caused a large reactor water level transient.
The breaker trip (non-safety related)
occcurred when water was sprayed into the breaker control panel by cleaning personnel.
Additionally, per operations procedures, the "Core Spray Out of Service" switch was placed in the "INOP" position to indicate the inoperable status of CS during the modification installation.
However, this status switch also energizes the "Loss of CS Logic Power" status indicating light on the control room panel.
When the fuses were pulled (which also causes this light to energize)
the indicating light was already on, due to the switch position, thereby masking the actual loss of the CS logic powe 'I
Licensee corrective action following the event included:
(1) training of electrical construction personnel and installation engineers concerning equipment operation and blocking, (2)
a review of open CWO's to ensure that none specified blocking as part of the work plans, and (3)
a human factors analysis on the CS "Out of Service" switch.
The Technical Specification LCO's for CS system were entered=:
based upon the Equipment Release Form (ERF) submitted for the PMR work.
LCO's were not entered for the other affected',
systems prior to work commencing as these LCOs were caused by the pulled fuses.
During the actual event the operators determined that the "A" generator was inoperable, and enteredx'""
the appropriate LCO, but were not aware of the other effects~.
until further investigation was performed after the fuses were replaced.
The NRC will not issue a Notice of Violation for this viola.
tion since:
(1) it was identified and reported by the licensee, (2) it fits in Severity Level IV (Supplement 1),
(3) it was promptly corrected, including measures to prevent recurrence, and (4) it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation.
Due to the masking level transient event and logic power status light, sufficient information did not exist to alert operators that the plant was in an Action statement condition~"
"
Additionally, although the LCO was not met,'the equipment affected (except Division I Core Spray)
was capable of performing its intended safety function.
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 determine that the report included the required information, that test results and/or supporting information were consistent with 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 1984 Special Report RCIC Injection The above reports were found acceptabl l4
'I
5.0 Monthl Surveillance and Maintenance Observation 5. 1 Surveillance Activities The inspector observed the performance of surveillance tests to deter-'ine 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 pro-cedure; test instrumentation was calibrated; limiting conditions for operation 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.l These observations included:
SR-178-001, Daily Verification of APRM Scram'nd Rod Block Set-points, performed on Unit 1 on August 21, 1984.
S0-282-001, Revision 0, Weekly Turbine Bypass Valve Cycling, performed on Unit 2 on August 28, 1984 S0-293-001, Revision 0, Weekly Turbine Overspeed Protection System+:-'.
Valve Cycling Test, performed on Unit 2 on August 28, 1984.
No unacceptable conditions were identified.
5.2 Maintenance Activities 5.2. 1
'D'iesel Generator Turbochar er Failure On September 10, 1984, during surveillance testing, the
'D'iesel generator (D/G) tripped on high vibration.
The D/G was run three more times while maintenance personnel monitored the D/G performance.
On these runs, the D/G exhibited a whining noise from the turborcharger area and the engine tripped on high vibration several minutes after starting.
The licensee declared the 'O'/G inoperable at 2:55 p.m.
and issued Work Authorization S44649 to investigate and repair/replace the turbocharger.
Intake air ducting was removed and the blower end of. the turbocharger was examined.
The blower end journal bearing had a large piece missing and a number of metallic particles from the bearing were retrieved.
No particles were found in the bearing oil lines.
The thrust bearing (TB) was not damaged and did not show excessive wear.
The licensee removed the turbocharger
l
h~
tf.
+l g
and replaced it with a spare (Serial No. 6771-T).
The spare unit was missing a journal bearing, thrust bearing and blower bearing sleeve because of previous maintenance on the
'C'/G and these parts were obtained from Cooper Industries on September 11.
The removed turbocharger has not been dis-assembled although inspections of it while assembled have not revealed any additional damage.
The turbocharger lube oil lines, oil filter and housing were inspected and nothing; abnormal was found.
The licensee intends to perform testing of the failed journal bearing and intends to ship the removed" turbocharger to Cooper Industries for refurbishment.
Post maintenance testing of the 'D'/G was satisfactory and the 'O'/G was declared operable at 8:45 p.m.
on September 12.
The inspector reviewed WA S44649 and maintenance procedure MT-24-014, Emergency Diesel Turbocharger Removal, Inspection and Installation, Revision 0 dated January 4,
1983.
The inspector also observed portions of the maintenance and discussed the job with Quality Control (gC), maintenance and engineering personnel.
Additionally, gA personnel conducted surveillances of housekeeping and post maintenance testing.
No significant problems were encountered with the maintenance and the inspector identified no unacceptable conditions.
The cause of the bearing failure is not yet known.
The results of examination and/or testing of the failed bearing will be reviewed in a subsequent inspection.
(387/84-26-01)
As a result of the inoperable 'D'/G, the licensee entered LCO 3.8. 1. 1 which requires testing of the remaining three D/Gs within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter.
During the testing, the 'B'/G demonstrated erratic performance.
Per surveillance procedure, S0-024-0013, during a manual start, the D/Gs are required to accelerate to 600 RPM and reach 4160 plus/minus 400 volts and 60 plus/minus 3 Hz within 10 seconds.
On several tests, the 'B'/G either tripped on overvoltage during the start or exceeded the
second start time by up to 2.5 seconds (the trips on over-voltage are related to the slow start).
When the 'B'/G was started a few minutes after a failed test, its perform-ance was satisfactory.
Between 6:00 p.m.
on September
and 9:30 a.m.
on September 12, the 'B'/G was tested
times with six satisfactory and six unsatisfactory tests.
On September 11, the 'B'/G was declared inoperable for approximately 20 minutes at 5:55 p.m.
because of test failures and again for about 40 minutes at 8:50 a.m.
on September
X'
for mainenance to check the starting air system.
The inspector discussed the performance of the 'B'/G with licensee management on September 12 and the licensee declared the 'B'/G inoperable at 10:40 a.m.
Since the 'D'/G was also inoperable at this time, Technical Specification LCO 3.8. 1. 1 Action Statement E requires on both Units 1 and 2, that with two D/Gs out of service, either restore a third D/G within two hours or be in Hot Shutdown within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
At 1:00 p.m.
on September 12, the licensee commenced a
5% per hour power reduction on Unit
in preparation for the shutdown.
Since Unit 2 was at a
lower power level (i.e.
70%), it did not initiate a power reduction.
At 8:45 p.m.
on September 12, the 'D'/G was restored, the shutdown halted and Unit 1 returned to 100%.
At 7:30 p.m.
on September 13, the 'B'/G was restored and the licensee cleared LCO 3.8. 1. 1.
The problem with the slow start times on the 'B'/G was corrected by changing out the fuel oil filters, filters in the starting air lines and blowing out the air lines.
However, later that day, the
'B'/G again exceeded the 10 second start time at 9:48 p.m.
and was declared inoperable.
The licensee's corrective actions on the 'B'/G will be further reviewed in the next inspection period.
The turbocharger failure on the 'D'/G and the problem with slow start times on the 'B'/G have been classified
,
as valid failures in accordance with Reg.
Guide 1. 108.
There have been four valid failures in the last 100 tests which, in accordance with Technical Specification Table 4.8. 1. 1.2-1, requires increasing the surveillance interval for the D/Gs to three days.
The inspector reviewed the D/G start log.
The latest three valid failures occurred on valid start numbers 195, 197, and 201.
The first valid failure within the last 100 tests occurred on valid start number 124 and hence, the D/Gs will remain on at least a
three day test frequency until valid start number 224.
Some discrepancies were noted on some D/G start log entries which were corrected by the licensee.
Review of 1983 ECCS Maintenance In accordance with DPRP Policy Statement No. 8.23, the inspector conducted a review of licensee's 1983 maintenance records to determine maintenance history of ECCS components.
The records were reviewed to determine if (1) the licensee is evaluating equipment failures for frequency and root cause; (2) maintenance errors are detected, evaluated and corrected, including root cause and (3) licensee's records are organized to support the above evaluation ~
~
The inspector reviewed the following reports:-
SSES Equipment Performance and Trending Analysis Reports for the 1st, 2nd, 3rd and 4th quarters of 1983; Plant Maintenance Information System (PMIS) Equipment History Reports for the 2nd, 3rd and 4th quarters of 1983 for the following systems:
ADS, Core Spray (CS),
RCIC, HPCI, RHR, RHR Service Water, Emergency Service Water, and Standby Gas Treatment System; 1983 Licensee Event Reports for the above systems; Selected 1983 Work Authorizations; Administrative Directive AD-gA-541, Maintenance Equip-ment Performance and Trending Analysis.
The licensee uses the PMIS System Equipment History Report to capture historical maintenance information.
Information including problem codes, cause codes, action taken codes and a
summary of the maintenance problem and action taken are extracted from all WAs and maintained in the PMIS data base.
A cause code exists to identify improper repair or installation.
However, the coding system is being revised to be more in line with the NPRDS reporting system and will contain more human deficiency cause codes.
PMIS Equipment History can be sorted by system, equipment identification or any of the other fields and hence, the records are organ-ized to support further review for trending.
On a quarterly basis, a maintenance engineer reviews PMIS data and prepares an "Equipment Performance and Trending Analysis Report".
This report identifies equipment which has become maintenance intensive.
The areas identified generally have had at least 20 maintenance actions in the quarter.
The report is provided for information to senior level PP&L management and is reviewed by PORC.
Investigations are conducted on equipment which has repetitive failures.
On an annual basis, a com-ponent, failure review is conducted which identifies specific components which have experienced a relatively large number of failures during the year.
The inspector further investigated the following maintenance actions based on the above document review:
RHR F017 valves The A and B LPCI injection throttling valves are 24 inch Anchor Darling globe valves used for throttling RHR in the shutdown cooling mode during il
~
~
\\
+,1*
shutdown or post accident.
In 1981, during a preopera-tional test, the licensee determined that these valves were inadequately designed for throttling RHR and would vibrate severely at lower RHR flows (about 4500 gpm).
At that time, the licensee modified the discs for better-throttling control.
In February 1983, while in shutdown=
cooling, an operator noticed the 'B'PCI injection
'hrottle valve (F017B) to be severely vibrating (Ref:
LER 83-34).
This caused a failure of welded attachments
.
on a pipe hanger and the valve lost its packing and position indication.
The valve internals were not inspected'n June 1983, operations had indication that the 'B'PCI loop was not full.
Investigation determined that the disc had separated from the stem of F017B apparently as a result of the previous vibra-<<
tion incident in February (Ref:
LER 83-91).
Two tack welds which attached the disc nut to the stem had broken.==
and the disc had backed off fronl the stem.
The valve was replaced and the tack welds increased in number and size.
An administrative limit of 10,000 gpm was established as the minimum throttle flow for shutdown cooling.
The licensee recognized that the 'A'oop might be affected by the same problem and wrote a
WA to inspect the F017A valve.
The licensee decided not to inspect the F017A until the next outage in December.:
1983, because no valve problems had been observed and the throttling service seen by the 'A'oop of LPCI was less severe than the 'B'oop, although some weld cracks of the 'A'alve hangers had been observed.
When F017A was inspected in December, the same tack welds were found broken and the disc had partially backed off the stem ( 1/2 inch of 6 inch travel).
These valves will be replaced with valves better suited for throttling during the first refueling outage.
Assessment:
This is an example of redundant components affected by the same root cause.
In the inspector's view the licensee properly identified and corrected the root cause of the valve problem and considered the effect on redundant components.
However, the F017A valve probably should have been inspected and repaired earlier based on its safety significance and history of problems with this type of valve.
RCIC Overs eedin The licensee had experienced several incidents of RCIC overspeeding during RCIC quick starts (Ref:
LERs 83-51,83-103 and 83-120)
and the problem has continued in 1984.
Maintenance action identified
e Jl
4
the cause of overspeeding to be slow response of the governor throttle valve coupled with the rapid opening of the steam supply valve.
Earlier corrective actions consisted of cleaning and relubricating the governor valve stem, rehoning the governor valve bonnet and linkage adjustments to reduce the governor valve travel.."
The problem was intermittent.
GE and Terry Turbine were consulted on the actions taken, although additional:-
overspeeding trips occurred.
The overspeeding problem was finally resolved following a staff visit to Woodward'-.
Governor Co.
and refurbishment of the RCIC EGR actuator.
"
The Woodward EGR used for the RCIC governor control at-.
Susquehanna (and apparently other plants) is obsolete and has been modified to incorporate a larger pilot valve and other changes'hese changes enable the RCIC governor to respond faster and hence, reduce the initial speed peaks.
Both Units 1 and
EGRs have been replaced.
Assessment:
Licensee correctly identified the root cause and noted that a design deficiency existed.
Apparently, equipment vendor (i.e.
GE and Terry Turbirre~))
representatives were not knowledgeable of the obsolete.
EGR in use which delayed earlier problem correction.
RCIC To az Inverter - The RCIC Topaz inverter at the remote shutdown panel (RPS) supplies instrument and control power for RCIC when RCIC is run from the RSP.
This inverter has a history of blown power supply fuses.
The power supply fuses were found blown at least seven times in 1983.
The problem is intermittent and earlier attempts to monitor the inverter with brush recorders did not reveal the problem.
The Unit 2 RCIC which has not experienced this problem, has a filter network in the inverter power supply.
The inspector was informed that this filter network will be installed on Unit
although it has not yet been accomplished.
Assessment:
The licensee has not vigorously pursued resolution of this problem and because it is intermit-tent, the licensee has been unable to identify the root cause and corrective action.
In Inspection Report 50-387/83-19, the Resident Inspector found that the licensee had exercised inadequate management control of this deficiency.
Licensee actions on this deficiency will be tracked by open item 387/83-19-0 ~Summar Inspector review of licensee 1983 ECCS maintenance activities indicates that, in general, repetitive failures of equipment are evaluated for frequency and root cause and consideration is given to the effects on redundant equipment.
No examples.*
of maintenance errors were 'discovered with the maintenance actions reviewed.
The licensee's record system supports evaluation of repetitive failures.
5.3 Surveillance Procedure Review The inspector conducted an in-depth review of surveillance procedures.
associated with the Unit 2 Core Spray System to ascertain whether the;-.
surveillance of safety-related systems and components is being conducted='",
in accordance with approved procedures as required by the Technical Specifications.
The inspector also examined the technical content of=
the procedures to verify that:
(1) testing ofysafety-related systems or components ensures compliance with the requirements specified in the Technical Specifications; and (2} the logic system functional test is a test of all logic components from sensor through and includ--'
ing the actuating device to verify operability.
The following items were reviewed:
Technical Specifications Section 3.3 FSAR Section 7.3.l.la.1.5 Administrative Directive AD-QA-422, Surveillance Testing Program S0-251-003, Revision 0, 18 Month Core Spray System and Logic Function Check SI-251-501, Revision 0, 18 Month Core Spray System Logic System Functional Test SI-283-301, Revision 0, Quarterly Calibration of CS Pump Discharge Pressure (ADS Permissive)
SI-283-201, Revision. 0, Monthly Channel Functional Test of CS Pump Discharge Pressure (ADS Permissive)
SI-280-301, Revision 0, Quarterly Calibration of Reactor Yessel Pressure (Core Spray System and LPCI Permissive)
L'
11'
SI-280-201, Revision 0, Monthly Channel Functional Test of Reactor Vessel Pressure (Core Spray System and LPCI Permissive)
SI-251-301, Revision 1, quarterly Calibration of Drywell Pressure Channels (Core Spray, HPCI, LPCI Permissive)
SI-280-303, Revision 2, 18 Month Cal,,ibration of Reactor Vessel Water Level Channels SI-280-203, Revision 2, Monthly Functional Test of Reactor Vessel Water Level Channels The technical review concluded that the surveillance tests for the Core Spray initiation logic meet the surveillance requirements stated:.
in the Technical Specifications.
No una'cceptable conditions were identified.
6.0 Startu Test Pro ram Unit 2 The inspector witnessed portions of selected tests to verify that:
Procedures with appropriate revision were available and used; Test changes were identified and implemented without changing the basic objectives of the test, in accordance with station procedures and Technical Specifications; Prerequisities were completed and verified; Initial conditions were met; Special test equipment required by the procedures was utilized and calibrated; Test was performed in accordance with the procedure; Results were satisfactory and met the acceptance criteria; Test exceptions or deviations were identified, documented and reviewed.
6. 1 Test Condition 2 Testin 6.1.1 ST 2 Relief Valve Rated Pressure Test On July 25, 1984, the inspector witnessed Startup Test ST 26.2, Revision 3, Relief Valve Rated Pressure Test.
This test consisted of manually cycling each relief valve (SRV)
at rated pressure to verify proper operation.
The test was
t'
performed at about 40% power.
Each valve was opened for about 15 - 25 seconds until generator output stabilized.
The following parameters were recorded:
reactor pressure change, tailpipe temperature, and acoustic monitor.
Reactor pressure dropped between 3 and 7 psig, generator output dropped by approximately
MW, and tailpipe temperatures increased to between 300 degrees F and 349 degrees F with each valve operation.
Two valves, the K and M SRVs, had to be retested because GETARS data was not obtained.
No other problems were encountered with the test.
ST 31. 1 - Loss of Turbine Generator and Offsite Power On July 26 and August 7, 1984, the inspectors witnessed startup test ST 31. 1, Loss of Turbine Generator and Offsite Power, performed from 30% power.
The purpose of the test was to demonstrate that safety systems such as the RPS, the diesel generators (D/G),
RCIC and HPCI function properly without manual assistance.
During the test setup, Unit 2 is electrically isolated from Unit 1 by lining up all Unit 2 4KV ESS busses to be fed from the T-20 startup transformer via ESS transformers 201 and 211.
Then the 4KV breakers from the Unit 1 offsite source (i.e.
ESS transformers 101 and 111).to the Unit 2 4KV busses are racked out and the 13.8KV tie breaker between T-10 and T-20 is racked out.
The test is then initiated by simultaneously opening the Unit 2 Main Generator 500KV output breakers causing a load reject and the startup transformer T-20 breaker to startup bus 20, causing a loss of offsite power.
On July 26, 1984, the test was initiated at 1:37 a.m., but none of the diesels started.
Unit 2 was without AC power for ll minutes before the first 4KV bus was restored.
This event was reviewed by a Region I inspection team and the results documented in Special Inspection Report 50-388/84-34.
On August 7, 1984 at 5:03 a.m.,
the licensee reperformed the test.
The reactor scrammed and the recirculation pumps tripped on the turbine control valve fast closure, the MSIVs shut on loss of the RPS MG sets and the reactor feed pumps tripped on loss of the condensate pumps essentially isolating the reactor.
All four diesel generators started and loaded on the 4KV busses within 10 seconds as designed.
The
'E'RV lifted to control reactor pressure six times during the 30 minute test.
The valve lifted within a few psi of its setpoint of 1076 psig and reshut, at approximately 990 psig each time.
The operators manually started RCIC at 5:35 a.m. (after test completion) at approximately -30 inches
C4, e
q4 Aw" f
vessel level.
The lowest vessel level reached was -31 inches.
Suppression pool temperature only increased from 83 degrees F. to 90 degrees F.
The test was successful and met the acceptance criteria.
The following problem was noted on the shutdown:
The 'A'PS MG set could not initially be restarted following power restoration and hence, the scram could not be reset, The MG set was subsequently restarted.
Electrical maintenance performed bench testing of the MG set supply breaker and found no problems.
The prob-lem, which has occurred previously, may be related to the breaker or contactor overloads which apparently trip on starting current if the MG set is restarted soon after it trips.
The problem is intermittent and the technial staff is pursuing resolution.
Licensee actions to correct this deficiency will be reviewed in a subsequent inspection.
(388/84-33-03)
v 7.0 Drawin Discre anc During followup of the loss of all AC power event on Unit 2, the inspector noted that GE elementary drawing Ml-C12-90 for Reactor Manual Control System had not been revised to incorporate DCP 20042.
OCP 20042 changed the power supplies to the Rod Position Indication System, Full Core Display and the Four Rod Display to Uninterruptable Power Supplies (UPS).
Inspector review of DCP 20042 noted that no Interim Drawing Change Notices (IDCNs) were issued for the M1-C12-90 series drawings, although other drawings such as load lists, termination drawings, etc.
were modified.
DCP 20042 was designed and implemented by Bechtel and was completed in October 1983.
Nuclear Plant Engineering (NPE) acknowledged that the GE Elementaries should have been revised since they are Class 1 drawings, and they issued DCN No.
84-2935'nd 84-2936 to revise these drawings.
The inspector also noted that the specific drawing Ml-C12-90 (GE No.
791E406WJ) for Unit 2 Reactor Manual Control System is not listed in NDI-QA-15.2.4,
"As Built Drawing Requirements" as a Class 1 drawing, although the Unit 1 drawing (79E406AE) is listed as Class 1.
The licensee has initiated a change to this procedure to correct this discrepancy.
8.0 Prep erational Test Pro ram The inspector met with licensee representatives, and through discussions and review of preoperational and acceptance test procedures, verified the status of Unit 1 and 2 on completed tests with no exceptions; completed tests with exceptions; and uncompleted tests with open and closed exception %sf1
'
Remaining open test exceptions have been transferred to the plant staff nonconformance report (NCR) program for resolution on disposition including the assignment of an NCR number to each exception.
The remaining open preoperational and acceptance test exceptions for Unit 1 and 2 that are to be resolved or dispositioned by transfer to plant staff nonconformance report program, will be carried as an unresolved item and are listed as follows:
Unit
P45. 1 FW P55.1 -- CRD P81.1 Fuel Handling P85. 1A Cath. Prot.
P99. 1 RB Cranes A41.1 Cooling Towers A67. 1 Loose Parts Monitor A76.2 Sampling A85.2 Freeze Prot.
Unit 2 P245. 1A P250. 1A P261.1A P279. 1A P281. 1A P281. 1B P299.1B A203. 1A A211.1A A219.1A A235. 1B A237.1A A239.1A A241.1B A243.2A A272.1A A272. 1B A295.1B A299.4A FW RCIC RWCU Area Rad Monitor Fuel Handling Fuel Handling RB Cranes 13.8 KV Service Water Service Water Fuel Pool Cooling Makeup Cond.
Refuel Water Cond.
Demin.
Cooling Towers Cond.
Tube Cooling Gas Radwaste Gas Radwaste H2 Seal Oil Rad Area Doors This is an unresolved item.
(387/84-26-02; 388/84-33-04)
When these exceptions are resolved or di spositioned this item will be closed.
With the transfer of the test exceptions to plant staff NCR program and the closing of unresolved items 388/83-04-01, 388/84-23-01, 388/84-23-02, and 388/84-23-03; this closes the preoperational test program for Units
and.0 Exit Interview On September 14, 1984, the inspector discussed the findings of this inspection with station managemen I