IR 05000352/1989012
| ML20248D917 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 07/28/1989 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20248D894 | List: |
| References | |
| 50-352-89-12, 50-353-89-19, NUDOCS 8908110167 | |
| Download: ML20248D917 (32) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 89-12 89-19 Docket No.
50-352 50-353 License No.
NpF-39 NPF-83 Licensee: Philadelphia' Electric Company Correspondence Control Desk P.O. Box 7520 Philadelphia, Pa 19101 Facility Name:
Limerick Generating Station, Unit I and 2 Inspection Period: May 29, 1989 - June 25, 1989 Inspectors:
T. J. Kenny, Senior Resident Inspector L. L. Scholl, Resident Inspector R. L. Fuhrmeister, Resident Inspector M. G. Evans, Resident Inspector A. G. Krasopoulas, Reactor Engineer J. H. Williams, Project Engineer D. T. Moy, Reactor Engineer R. M. Loesch, Radiation Specialist J. Gadzala, Reactor Engineer Approved by:
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Lawrence T. Doerflein, Chief',' Projects Ddte Section 2B Summary:
Routine daytime (331 hours0.00383 days <br />0.0919 hours <br />5.472884e-4 weeks <br />1.259455e-4 months <br />) and backshift/ holiday (51 hours5.902778e-4 days <br />0.0142 hours <br />8.43254e-5 weeks <br />1.94055e-5 months <br />)
inspections of Unit I and 2 by the resident and region based inspectors consisting of (a) plant tours, (b) observations of maintenance and surveillance testing, (c) review of LERs and periodic reports, (d) review of operational events and (e) system walkdowns.
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8900110167 890728 PDR ADOCK 05000352 O
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Areas Inspected: Resident safety inspection of the following areas: opera-tions, radiological controls, turve111ance testing, maintenance, emergency
. preparedness, security, engineering / technical support, safety assessment /
assurt.nce of quality, review' of licensee event reports, open item followup, and commencement of fuel loading >1nto Unit 2.
Results:
Unit 1.
Three violations were identified concerning technical specifi-cations and failure to follow procedures..Rection 2.1.3.1 documents the failure.to perform Technical Specification (TS) required electronic calibrations of the Primary Containment Post-LOCA High Range Monitor.
Section 2.1.3.2 documents the failure to follow procedures on two occasions l-and Section 4.1 documents the licensee's Radiation failure to perform tiie necessary maintenance on control rod drive accumulator check valves resulting in operating the reactor contrary to'T.S. with inoperable accumulators in accordance with T.S. 4.1.3.5.b.2.
Unit 2.
This inspection documents the review and closeout of various Open Items, NRC Bulletins, Construction _ Deficiency Reports, and TMI Action Items.
Various Preoperational Test Results Reviews were also accomplished. The inspectors also witnessed preparations for the fuel
' load license issuance, the license issuance,' and initial fuel loading.
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DETAILS 1.0 Persons Contacted Within this report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspection activity.
2.0 Operational Safety Verification
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2.1 Unit I (71707)
2.1.1 The inspectors conducted routine entries into the protected areas of the plant, including the control room, reactor enclosure, fuel floor, and drywell (when access was possible). During the inspection, discussions were held with operators, technicians (HP & I&C), mechanics, security personnel, supervisors and plant management. The inspections were conducted in accordance with NRC Inspection Procedure 71707 and affirmed the licensee's commitments and compliance with 10 CFR, Technical Specifications, License Conditions and Administrative Procedures.
2.1.2 Inspector Comments / Findings Unit 1 began the report period operating at approximately 78% of full power.
Power is being administrative 1y restricted to less than 80% until feedwater copper concentration is reduced to less than 0.2 parts per billion. The licensee imposed this limit in order to minimize the potential for fuel cladding failures due to crud induced localized corrosion.
During a licensee self assessment of the Appendix R safe shutdown enalysis, the following discrepancies were identified:
1.
The fire protection evaluation report does not presently recognize the high pressure coolant injection (HPCI) or reactor core isolation cooling (RCIC) barometric conder.ser subsystems
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(condenser / collection point for seal steam and valve
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leakoff) as required for safe shutcown.
The HPCI barometric condenser is properly protected; however, j
the RCIC barometric condenser subsystem has not been l
protected against the effects of a fire in +5e
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control complex.
In the event of a desig" hisis
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fire, this may affect the operation of RCiC which is I
required to achieve safe shutdown.
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A valid or spurious start of the "A" RHR pump in conjunction with fire induced damage to the RHR minimun.
' v valve cables (which could disable the valve in tne closed position) might cause damage to the RHR pump which is required to achieve safe shutdown.
3.
A fire in certain plant fire areas could result in the spurious opening of certain high-low pressure interface valves.
Specifically, the spurious opening of the Residual. Heat Removal (RHR) shutdown cooling suction valves could result in possible overpressure-zation of the low pressure piping, and the spurious opening of 3 Reactor Water Cleanup (RWCU) valves could result in loss of reactor vessel inventory beyond makeup capabilities of the Reactor Core Isolation Cooling (RCIC) system.
4.
A fire in tha Auxiliary Equipment Room could result in the loss of ventilation to the Remote Shutdown Panel (RSP) resulting in possible infiltration of smoke into the RSP room.
This could prevent operator access to the room thereby preventing safe shutdown.
5.
The Limerick Generating Station Fire Protection Evaluation Report (FPER) states that a loss of off-site power is assumed at the onset of a fire and that a portable radio communication system will be provided for use by the fire brigade and operations personnel as required to achieve safe shutdown.
However, a fire in certain plant areas could result in the loss of radio communication system between the time that all on-site power is unavailable and the restoration of on-site power.
6.
The FPER also states that if the control room and/or auxiliary equipment room fan systems are disabled, temporary ventilation can be provided by opening doors and using portable fans for circulation.
However, in the event of a design basis Appendix R fire in the control structure fan room, coincident with a loss of off-site power, this statement could not be supported.
Electrical power and consequently the portable fans, would not be available to provide temporary ventilation.
The above conditions have been reported to the NRC via the ENS.
The following corrective actions have been taken on Unit 1:
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'ltem Nos.1, 2, 3 - affected fire areas have fire
~ watches established. Permanent plant modifications.
.are being prepared to correct the. design deficiencies.
Item No. 4 - A plant modification and procedure
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changes have been implemented to correct this I
deficiency.
Item No. 5 - A plant modification?has been'
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implemented u provide a backup power supply to the communications system.
Item No. 6 - Fans, cabling, and an emergency diesel have been procured and tested to ensure that temporary. ventilation can be provid'd if necessary.
Procedural changes have been 1mpleunted to instruct personnel on'the operation of this' equipment.
On June 8, 1989 the licensee conducted a plant' evacuation
' drill.
Licensee evaluators determined the drill was successful,- however, they plan to conduct additional training with security force personnel so that the list of persons who cannot be accounted for can be compiled more rapidly.
On June 17, 1989, during the performance of a monthly surveillance test on the drywell to suppression space vacuum breakers, one. vacuum breaker could not be opened (PSV-057-1370-1). Technical Specification.4.6.4.1.b.1
' requires the vacuum breakers to be cycled through one complete cycle of full travel at least once per 31 days.
Troubleshooting of the test circuitry determined that the solenoid valve which supplies air to the gas actuator was not being energized when the test button was depressed.
Both the solenoid valve and an associated relay in the-
- test circuit are located in the drywell thus preventing access to facilitate repairs. On June 19, 1984 a special procedure was performed which accomplished partial stroking of the vacuum breaker by establishing a slight differential pressure between the suppression space and the drywell.
During further troubleshooting the vacuum breaker fully opened several times when the hand switch was placed in the " Test" position.
Normally a pushbutton must also be depressed to complete the test circuit. This indicates that the contacts on the test relay which are normally open are remaining closed at all times.
The reason for this condition.<ill be investigated when drywell access is possible.
In the interim the licensee has declared the monthly test acceptable and performed a safety evaluation to review any safety implications due to
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the malfunctioning relay. The inspector reviewed the evaluation and had no concerns regarding the vacuum breaker operability in light of the malfunctioning test circuitry.
2.1.3 Radiological Controls (83750)
2.1.3.1 Accident Monitoring Instrumentation On June 13, 1989, the inspector noted that Unit I was operating without the minimum number of operable Primary Containment Post-LOCA High Range honitor channels. The Containment Post-LOCA High Range Monitors (291A, 291B, 291C and 2910) had been calibrated March 3-5, 1989. The monitors have a range of 1 R/hr_ to 1E8 R/hr (8 decades). The inspector noted that surveillance tests (ST's) ST-2-026-407-1, ST-2-026-408-1, ST-2-026-409-1 'nd ST-2-026-410-1 did not ensure compliance with the Technical Specifications (T.S.). The procedures included a radioactive source calibration of the single decade below 10 R/h and an electronic calibration of the recorder but failed to provide for an electronic calibration of the upper seven decades.
Technical Specification 3.3.7.5 requires that a channel calibration of the Prir.ary Containment Post-LOCA High Range Monitors be performed each refueling cycle. In addition, it further defines, in Table 4.3.7.5-1, that the channel calibration shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/h and a one point calibration check of the detector below 10 R/h with an installed or portable gamma source.
Failure to perform the necessary electronic calibrations of the seven decades above 10 R/h is an apparent violation of Technical Specification 3.3.7.5 (50-352/89-12-01).
When brought to the licensee's attention, all four radiation monitors were immediately recalibrates utilizing a Temporary Procedure Change (TPC).
Although the pro:edures directly referenced the T.S I
requirement, the licensee's technical review and approval process failed to identify the procedural inadequacy.
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ow2r (LOOP) Test The test results packaga for TP2P100.1 was reviewed in order to assure the prcper conduct of the test and
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the achievement of test results which satisfied the
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test purpose, objectives and acceptance criteria.
The test results verify that the equipment response to the LOOP fulfills the operational requirements of the FSAR and technical specifications.
2.2.2.2.
Preoperational Test 2P-58.1 - Reactor Protection System The Reactor Protection System preoperational test procedure was performed to demonstrate the ability to adequately fulfill the operational requirements. A review of these tests results revealed that all test criteria were satisfied and that deviations were properly identified and resolved.
The inspectcr had no further questions regarding this package.
2.2.2.3.
Preoperational Test 2P-83.1 - Main Steam System The purpose of the Main Steam system preoperational test procedure was to demonstrate the proper cperation of the main steam system and the main steam isolation valve leakage control system to adequately fulfill the operational requirements.
Inspector reviewed the test results and unresolved test exceptions which were identified by the Tr.st Rtview Board. All the test exceptions were tracked by startup work order (SWO) or startup field report (SFR). All test criteria were satisfied and the deviations were properly identified and resolved.
The inspector had no further questions regarding this test package.
2.2.2.4.
Preoperational Test 2P-53.1 - Standby Liquid Control System The inspector reviewed Preoperational Test Procedure 2P-53.1, " Standby Liquid Control," to verify that test acceptance criteria were met and adequate evaluation of test results was made by the licensee.
Changes to the test procedura and test exceptions were also reviewed. All test criteria were satisfied and the
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deviations were properly identified and resolved.
The inspector had no further questions regarding this test pr iage.
2.2.2.5.
Preoperational Test 2P-61.1-Reactor Water Cleanup System The inspector reviewed the results of preoperational test 2P-61.1, Reactor Water Cleanup (RWCU) System, Revision 0.
The inspector verified that al'. test
acceptance criteria were met. The inspector reviewed all test exceptions'and verified proper closure including retests if required. -The inspector noted that a test exception was identified involving the failure of the RWCU pumps' available net positive suction head (NPSH).to meet design requirements. The exception was closed following recalculation of the pumps' available NPSH using a different method for calculation.
The inspector discussed the test exception with the test director and independently verified that the RWCU pumps available NPSH was adequete.
The inspector had no further questions.
2.2.2.6.
Preoperational Test 2P-78.1-Startup Range Neutron Monitoring The inspector reviewed the result. of preoperational test procedures 2P-78.1, "Startup Range Neutron Monitoring (SRM)," Revision 0.
The inspector reviewed the test procedure, including temporary change notices and test exceptions.
The inspector discussed the test results including resolution of several open test exceptions with the test director and verified that all acceptance criteria we e satisfied.
No unacceptable conditions were icantified.
2.2.2.7.
Preoperatiegal Test 2P-83.2-Automatic Depressurization System The inspector reviewed the results of pts.. rational test procedure 2P-83.2, " Automatic Depressurization System (ADS)," Revision 0.
The inspector reviewed the
"as-run" copy of the test procedure, procedure changes, and test exceptions including retests when required. All acceptance criteria were satisfied.
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2.2.2.8.
Preoperational Test 2P-58.2-Redundant Reactivity l
Control System (RRCS)
The inspector reviewed the test results package for 2P-58.2, " Redundant Reactivity Control System." Proper documentation and resolution of test exceptions was-verified,'and all other data was confirmed to t.
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within acceptabla tolerances. Test change notices l
were reviewed for content, proper review, and impact on testing.
No discrepancies were noted.
2.2.3.
Power Ascension Test Program (PATP)
D2300,72400,72500,72509,35501)
2.2.3.1'
Overall Power Ascension Test Program On June 9, 1989 the Plant Manager and the Plant Operations Review Committee (PORC) determined that it was satisfactory to commence Test Condition, Open Vessel which includes Initial Fuel Loading and Zero Power Testing.
STP 1.1, Prefuel Load Data - Chemistry, was begun in anticipation of Fuel Loading.
Limerick Unit 2 received a license authorizing fuel loading and precriticality testing on June 22, 1989.
Initial Fuel Loading began on June 23, 1989 per STP3.1, Fuel Load.
(See discussion in Sectiors 2.2.1)
2.2.3.2 Power Ascension Test Procedure (PATP) Review The licensee's PATP administrative and startup test procedures listed in Attachment A were reviewed for their conformair. with the rt quirements and guidelines of the references listed in Attachment B and for the applicable attributes listed in Inspection Report 50-353/80 63, Section 2.2.
During review of STP-5.6, " Rated Reactor Prassure Scram Testing," Revision 1, the inspector noted that the procedcre had recently been changed to allow conduct of this test during Test Condition (TC)
Heatup or during the vessel hydrostatic test in TC,
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Open Vessel. The procedure was originally written to be conducted during TC, Heatup, with the mode switch in startup, the shorting links installed since adequate shutdown margin (SDM) would have been demonstrated during STP4.1, "In Sequeace Critical," and the reactor l
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The inspector noted that the procedure revision only included an additional. statement in the discussion section allowing performance of the test during the vessel hydrostatic t <t in TC Open Vessel.
During open vessel testing, the mode switch would be in refuel and the shorting links would be removed since l
adequate SDM would not have been demonstrated.
The inspector noted that the procedure had not been mcdified to reflect these changes in plant conditions.
The inspector discussed this issue with the licensee startup test program representative who stated that the procedure would be revised. The inspector will further review the revised procedure when issued.
During review of STP-99.0, " Master Startup Test Procedure," and subtests 99.1 through 99.6, the inspector had several questions which were discussed with a licensee representative and resolved as follows. The inspector noted a few minor discrepancies between the sequence of testing listed in the subtests and that described in STP-14.6 and STP-27.2. The licensee representative stated that procedures STP-14.6 and STP-27.2 would be revised to adequately reflect when testing was planned to be conducted.
In addition, the inspector reviewed STP-99.0 and the subtests against FSAR Figure 14.2.9,
"Startup Test Sequence," and noted two discrepancies between Figure 14.2.9 and the testing described in the subtests.
Specifically STP-33, " Piping Steady State Vibration Testing," is listed in Figure 14.2.9 as being conducted in TC-5 while no testing was listed in STP 99.6.
In cddition, STP-33 did not include a requi*ement for conduct in TC-5.
The licensee representative stated that STP-33 would be modified to incluce testing in TC-5.
Figure 14.2-9 also listed STP-25, " Main Steam Isolation Valve Performance Verification," as being performed during TC-6 with the requirement of determining the maximum power level the test can be achieved without a reactor scram.
The licensee representative stated that the testing would be done in TC-5 per STP-25 and that a Licensing Document Change Notice would be generated to update FSAR Figure 14.2.9.
The inspector had no further questions.
Except for for the items discussed above, the proce-dures reviewed were found to satisfy the attributes identified in Inspection Report 50-353/89-03 and to adequately meet the requirements and guidelines of the reference _ _ _ _ _ _ _ _ -
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2.2.3.3 QA/QC Interfaces with the PATP The inspector met with representatives of the licensee's Nuclear Quality Assurance organization to discuss planned activities durir.g the PATP. Monttor-ing of Startup Test Procedure 'STF) testing is currently ongoing and will continue throughout the test program.
Review of STP result packages will be performed prior to PORC review and approval at the completion of a test plateau. A series of audits beginning with fuel loading and ending with the fuel we
.nty run will be conducted.
The aucits will adoress items such as qual'fication or test personnel, Test Exception Reports (TER) and Startup Test Change Notices.
In addition, the Independent Safety Engineering Group (ISEG) will independently evaluate and review safety evaluations for TERs associated with acceptance criteria deviations and review selected test result packages for technical accuracy. The results of these Quality Assurance activities will be factored into the Licensee's Powar
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Ascension Self-Assessment Program for evaluating overall station readiness to continue power ascension testing.
The inspector discussed various aspects of the above activities with the licensee representatives and reviewed the licensee's guidelines for monitoring of testing activities. The inspector found the Quality Assurance plans for monitoring of power ascension testing activities to be adequate.
The inspector had no further questions at this time.
3.0 Update of Open Items (92701, 94300)
3.1 Fire Protection Deficiencies Unit 1/ Unit 2 The following construction deficiency reports (CDR's) were reviewed by the inspector to verify that the issues involved were adequately addressed by the licensee.
These CDR's were identified by the licensee as a result of a reanalysis and re-evaluation of the /ppendix R Program for the Limerick station.
When the deficiencies identified impacted Unit I the licensee issued a Licensee Event Report (LER) in accordance with 10 CFR 50.72 and 50.73.
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f Ll These items and their' disposition by NR0 are as follows:
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-(Closed) Construction ~ Deficiency Report (CDR) 188-00-08)
Licensee Event Report (LER)88-031 Loss of Level and Pressure Indication at the Remote Shutdown Panel (RSP) and loss of RCIC' injection capability due to Lack of Control Circuit Isolation The iicensee determined that a fire could cause the loss of the AC' power supplyfto the RSP thus causing.the loss of the level and pressure indication. The inspector reviewed modification L
package No. 5950.which corrected the condition by providing a DC power source to the_ instruments.
This CC power source is.
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available at the RSP and consists'of batteries and a charging
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Regarding the loss of the Reactor Core Isolation Cooling (RCIC)
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system the licensee'has determined that a fire in'the control l
room (CR)'or cable spreading room has the potential of disabling the'RCIC-system if the turbine speed control and indicating
' circuits' fail before the transfer of the RCIC control system-to the remote shutdown. panel takes place. To correct this problem the licensee has installed electrical isolation devices to
. prevent fire damage _to the control and indication circuits.
This modification assures that when the operators evacuate the CR and take control of the plant at the remote shutdown panel all RCIC contr'ols are operational.
The inspector reviewed modification package 5962-2 which is the design for this modification and did not identify any unacceptable conditions.
This item is closed, b.
(Closed) CDR 89-00-03 (LER 89-02) Loss of RCIC from the inadvertent closure of the RCIC steam supply inboard isolation valve The licensee has determined that when the RCIC system is required to provide reactor coolant inventory, a fire has the potential of damaging the power supply to the RCIC steam supply inboard isolation valve rendering the system inoperable.
This valve is powered from the Division III power source and will close upon receipt of a RCIC Division III isolation signal.
Division III was not considered to be required when the shutdown methods using RCIC are implemented, therefore, the atsociated cables were not protected. The licensee has c;Mpleted Modification No. 5994-2 which added an emergency manual transfer switch that provides Division I power to the valve This modification will enable the operators to open the valve in the event it closes from fire damage to the Division III power source.
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Inadvertent HPCI system initiation can cause the loss of both the HPCI and RCIC system by flooding the reactor The licensee has determined that when the High Pressurc Coolant Injection (HPCI) system is not required for shutdown, a fire has
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the potential for causing the inadvertent initiation of the
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system and prevent its tripping either remotely or automatically.
Under these conditions the HPCI system would fill the reactor vessel to the steamlines, flooding the steam supply headers to both HPCI and RCIC pumps causing the loss of safe shutdown capability.
The licensee has installed an HPCI trip switch at the remote shutdown panel.
This switch assures that the operators can trip the HPCI if required.
Loss cf HPCI by fire induced shorts on the steam leak detection system which could cause the HPCI to tri_p.
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The licensee has identified the concern that a fire induced hot short to the HPCI steam leak detection circuits could cause the closure of the HPCI steam supply containment isolation valves.
This condition exists in Unit 2'anly.
Three fire areas are affected.
For fire area 59G, it has been determined that the HPCI system is not required for shutdown with a fire in this area.
For a fire in areas 68W and 70W the licensee has determined that although five steam leak detection system sensors could trip HPCI, steam leak detection system by pass switches have been provided to isolate the leak detection logic from the steam vcive circuits.
The actions described above satisfy the NRC concerns and the items are closed.
c.
(Closed) CDR (89-00-05) (LER-89-12) RCIC Injection loss due
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to Feedwater I;31ation
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The licensee has determined that a fire in the control room or the cable spreading room has the potential for causing the spurious closing of the feedwater header "B" inboard containment isolation valve (HV_41-2-F011B). Because the RCIC system discharges into the reactor vessel through the feedwater system the inadvertent closure of this valve would prevent RCIC system coolant injection into the vessel.
To correct this condition and to prevent the inadvertent closure of this valve, the licensee has locked the valve breaker open and revised the Procedure GP-2 " Normal Plant Start Up" requiring the breaker to be locked open.
This item is resolve ;
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(Closed)'CDR.(89-00-06) Possible Loss of Coolant from
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inadvertent CS Valve Opening
- The licensee has determined that normally closed core spray (CS) system valve, HV-52-2F037, has the potential for' opening
' inadvertently if a fire occurs,in fire area 70 west.
For a fire in.this area the HPCI system is relied on to provide reactor coolant make-up. The HPCI system discharges into the vessel via the CS piping down stream of this normally closed-valve.
If this valve opened while the HPCIjsystem was running, flow from the HPCI system could be diverted into the CS' system.
Because of the relief valves in the CS system downstream some'
of the coolant could be lost.
'The. licensee has rerouted the control cables associated with-this valver within fire protected cable trays. The. corrective actions for Unit I were different in that a modification preventing.the valve from a spurious opening was issued. An analysis performed by the licensee for this addition has determined that although some.of coolant water could be lest this would not affect safe shutdown.
This item is resolved.
e.
(Closed) Unresolved Item (50-353/89-06-03) and Hfgh/ Low Pressure Interf ace Analysis (Portion of CDR 89-00-10)
This item identifies the' licensee's High/ Low pressure interface analysis did not demonstrate adequate protection. The licensee prepared a new High/ Low Pressure interface analysis to satisfy this concern.
This analysis determined that the following unacceptable High/ Low Pressure interfaces exist:
1)
The RHR shutdown cooling valves HV51-1F008 for Unit 1 and HV51-2F008 for Unit 2 could spuriously open from a fire induced hot short and pressurize the RHR piping system above its design pressure.
The licensee's corrective action was to lock open the valve breakers thus preventing the spurious opening of the valves. Although this corrective action is adequate from the fire protection standpoint the licensee considers it to be an interim solution. A future modification would allow operation without entering the reactor enclosure to close the breakers.
This item is closed.
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2)
The Reactor Water Clean Up (RWCV) valves HVC44-2F031, HVC44-2F033 and HVC44-2F034 or HVC44-2F035 could spuriously open as a result of a fire. Opening of all these valves would create a blowdown path from the reactor to either the condenser or to the equipment drain tank.
To correct this condition the licensee installed a disconnect switch on the power supply to valve HVC44-2F031. This switch is located outside the area of concern.
In addition the licensee routed the cable from the switch to the valve in a conduit to prevent the possible opening of-the valve by a hot short.
The same condition exists at Unit 1.
The licensee has not implemented a modification to correct this condition for Unit 1, however, a fire watch I,as been placed as an interim compensatory measure.
The licensee plans to install a modificton when plant conditions permit. The above' actions satisfy the NRL concerns regarding High/ Low pressure interfaces. This item is closed.
f.
(Closed) CDR 89-00-10 Loss of RHR Pump 1(2)AP202 from_a Fire Damaging the Controls of the Minimum Flow Line Isolation Valve The licensee has determined that a fire in the Control Building complex has the potential for preventing the opening of the minimum flow valve HV51-1(2)F007 of RHR pump 1(2) AP202 ((2)
for Unit 2).
If this valve cannot be opened because of fire damage to the cont al logic, and if the RHR pump starts spuriously as a result of fire damage the RHR pump can fail.
The licensee reviewed this concern in a safety evaluation performed in accordance with 10 CFR 50.59 and determined that the position of the minimum flow line valve HV51-1(2) F007 can be changed from normally closed to normally open.
The licensee committed to revise the Operational Procedure to reflect this change prior reaching 75 psi on Unit 2.
For Unit I the licensee committed to change the valve position and associated procedures expeditiously.
This item is closed.
Loss of HPCI and RCIC caused by the loss of room coolers The licensee has determined that a fire in several plant areas has the potential for causing the loss of the room cooling in the HPCI or RCIC rooms.
Failure of the room coolers could cause high temperature and humidity conditions in these rooms which could result in the faiiure of required system components, tnus L_ _ - _ _
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causing the. loss of the HPCI or RCIC functions. The licensee performed an analysis that identified the components that are required and also identified.which components could fail under q
these environmental conditions. The licensee implemented a~
modification that installed environmental. seals to components-subject to damage. The inspector reviewed the modification and found no unacceptable conditions.
Loss of Positive Pressure'in the Remote Shutdown Panel
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The licensee had committed to maintain a positive pressure in
,the Remote Shutdown Panel (RSP) Room to' prevent' smoke infiltration from a fire -in the adjacent Auxiliary. Equipment.
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' Room (AER). The positive pressure could be maintained by the use of the room ventilation system..However, the licensee determined that a fire in the AER has the potentia 1Lfor damaging-or. disrupting:the RSP room. ventilation thus the objective of keeping'the RSP room free of. smoke by the.use of the: ventilation-system could not be met.
In. order to correct this problem the licensee revfsed their commitment.
To maintain'the RSP room free of smoke in the event of a fire the licensee has installed ip smoke dampers in the duct work and sealed all doors and room penetrations to prevent smoke infiltration.
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The above actions satisfy the concern and CDR 89-00-10 is
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resolved.
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LER (89-023) Lack of adequate suppression pool level and i
and temperature indication _at the Control Room and Remote Shutdown Panel The licensee has determined that a fire in the Cable Spreading Room (CSR) the Control Room (CR) or the Auxiliary Equipment Room (AER) has the potential for damaging the AC powered instrument indication of the Suppression Pool Temperature at the remote shutdown panel.
In addition the licensee determined that the existing suppression pool temperature indication at the RSP was not a true indication because it was the temperature of the RHR suction line.
In order to correct this condition the licensee has added suppression pool temperature indicaticn for the RSP,
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using suppression pool temperature elements.
Power for this instrument is provided from a Class 1E DC power source. The licensee has also determined that a fire in several plant area:;
has the potential for damaging suppression pool level irdication C
in the CR which is required at the RSP. To correct these
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a deficiencies the licensee performed an analysis to identify the level instruments required for use in each of the five shutdown methods (A, B, C, D & R). The analysis identified the areas that the instrumentation components require additional fire protection (fire wrap) or separation.
In addition the licensee has added level indication at the RSP to use if a fire causes control room evacuation. The above actions satisfy the concerns and this item is closed.
h.
(Closed) (CDR 89-00-11) Loss of ability to communicate using hand held radios during a fire requiring CR evacuation The licensee has identified that a fire has the potential for damaging the hand held radio system required for communications, during shutdown operations, in the event of a fire. The loss of communications could occur as a result of' damage to the AC power supply for the hand held radio system repeaters. The licensee-implemented modification No. 5993-0 which provides 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> battery back-up for the radio system. This assures radio communications between the control room, the remote shutdown panel room, and the Operational Support Center (OSC).
[ Closed) Unresolved Item (50-352/89-06-01 and 50-353/89-06-01)
Issuance of Safe Shutdown Procedures In January 1989, the NRC inspected the licensee's safe shutdown capability and determined that the shutdown methodology used by the licensee is acceptable.
This was documented in the NRC report 50-352/89-06 and 353/89-06.
However, at the time this inspection was conducted the NRC could not verify that the licensee could shutdown both units.
During this inspection the NRC reviewed the shutdown procedures and walked down portions of these procedures to verify their adequacy.
The procedures reviewed were procedure SE-1, Remote Shutdown and SE-8, Attachment A, B, C and D, Safe Shutdown Methods A, B, C and D.
The NRC also reviewed the acceptability of the repairs performed during the last cold shutdown and did not identify any unacceptable conditions.
The last inspection also documented that when the licensee is using shutdown methods, C or D the core may become uncovered.
These methods require the depressurization of the reactor using the Automatic Depressurization System (ADS) and then using low pressure coolant injection (LPCI) to flood the vessel. At the time of that inspection the licensee did not have an analysis indicating the acceptability of these methods.
The licensee has prepared two Analyses one by General Electric that is plant specific and it is titled " Safe Shutdown Analysis for Fire Events" and the other by Bechtel Corporation titled " Time Line Study for Safe Shutdown Analyses PECo Limerick Generating Station Units 1
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The GE analysis concluded that when shttdown methods C and D are used some brief core uncovery may occur.
However, the calculated peak cladding temperature is low enough to preclude any fuel damage. The Bechtel analysis demonstrates through a time line study that using the shutdown procedures, implemented with the minimum complement of operators, the peak cladding
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temperature will be 811 F before the LPCI injection.
l The above is acceptable and this item is resolved.
j (Closed) Unresolved Item (50-352/89-06-03 and 50-353/89-06-02)
Lack of High Impedarce Fault Analysis and Fuse Replacement procedure The licensee performed an analysis to review the High Impedance Fault concern for both Limerick Units.
The assumptions for this analysis were evaluated by NRC/NRR and were found acceptable. The licensee's analysis determined that there are no high impedance fault concerns at Limerick Unit 2.
The analysis for Unit 1 identified feur buses that require restorative procedures.
The licensee believes that because the assumptions made in producing this analysis are conservative when the concern is reevaluated the need for restorative procedures may be eliminated. The analysis reviewed by the inspector satisfies the NRC concern.
Regarding the fuse control concern, the licensee has developed a Computerized Fuse Index file that will be used when fuses need to be replaced. A review of this fuse index did not identify any unacceptable condition. This item is resolved.
k (Closed) Violation (50-352/89-06-02) Lack of 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> Fire Barrier on the wall separating Unit 1 from Unit 2 cable spreading rooms This violation identified that the fire door on the wall separating Unit I from the Unit 2 cable spreading room was not fire rated. This was because the door Fad been modified to be held closed with magnetic contacts instead of a latching mechanism.
The license repaired the door which is now properly fire rated. The licensee's other preventive actions included a review of the plant doors to assure that a similar condition does not exist elsewhere.
Two additional doors were identified that contained magnetic latches.
However, they do not separate safe shutdown components. The licensee actions are adequate and the violation is closed.
The issues described in subparagraphs (a) through (k) above are technically resolved. However, they constitute potential enforcement issues, and will be subjected to further review by NRC.
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(Closed) Construction Deficiency Report (88-00-11) and Unresolved Item (50-353/88-18-01).
NRC Inspection Report 50-353/88-18 documented the review of the Core Spray-System preoperational test, 2P51.1.
In this report the NRC inspector questioned the rationale for selecting 203 feet:11 inches as the minimum suppression pool level which could be expected during a loss of coolant accident.
Based on this concern additional engineering reviews were performed and resulted in a new expected minimum level of 199 feet 11 inches.
Since a suppression pool water level following a LOCA that is lower than the water level used for design purposes could affect the primery containment and'ECCS design functions, the following potential problem areas were identified by the licensee:
a.
Change in Hydrodynamic Loads b.
Lower RCIC/HPCI Turbine Exhaust Sparger Submergence c.
Lower Available NPSH to the ECCS pumps d.
SRV Quencher Instability Concerns e.
Uncovering SPTMS Temperature Sensors f.
Post-LOCA Dose Calculations g.
Jiaphragm Slab Load Due to Weight of Water h.
Uncovering Suppression Pool Narrow Range Level Transmitter Lower Leg i.
Containment Penetration Water Seal Integrity Evaluations of these potential problem areas resulted in two required corrective actions:
1) Startup Work Orders (SW0s) 249A-364 and 251 were generated to revise net positive suction head (NPSH) calculations for the ECCS pumps.
The revised calculecions showed that adequate NPSH remained available.
2) Since a suppression pool level of 199 feet 11 inches would result in the suppression pool temperature monitoring probes becoming uncovered plant modification 5973 was implemented to increase the probe length to ensure submersion under all accident conditions.
SWO 259A-084 implemented this modifica-tion for Unit 2.
A similar modification was performed on the Unit I system during the second refueling outage.
Based on the above actions this item is closed.
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b.
(Closed) Unresolved Item'(50-353/87-02-02)
Identification and resolution of. General Electric Service'
Advice Letters (SAL's) that affect the Limerick Plant. The Project Management-Division has the responsibi ity for control of SAL's as well as other documents. These documents are controlled and reviewed in accordance with LGS Qcality.
- i Assurance Plan Volume I. Appendix A and are tracked on the f
CORLOG database.
By procedure, SAL's'are reviewed by a group-under the -Limerick Vice President 'as well as groups in engineering.. The licensee contracted with.GE for a' review of
- SAL's for Limerick Unit 2.
This review consisted of:
Identify GE supplied components.
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Obtain SAL's.from GE departments.
607 SAL's were obtained
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from 23 GE Product Departments.
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Deve16p list of SAL's that could affect Limerick Unit 2, 233 SAL's were determined to have possible: significance.
Assess application of SAL's to Limerick Unit 2.
A team of
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experienced GE engineers performed the assessment.
Bechtel-reviewed and approved each SAL package.
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PECo approved each SAL package closure.
The review found no evidence that SAL's with direct fuel load impact had not been' implemented.
Based upon the inspectors review of licensee's actions this item is closed.
c.
(Closed) Unresolved Item (50-353/89-13-02) Testing of HPCI Lube Oil Return Temperature Sensors The inspector had previously noted that HPCI pump bearing l
return temperatures'were not recorded during conduct of-l preoperational testing.
Interviews with licensee personnel l.
indicated that the temperatures were monitored but not
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recorded. An additional pump run was conducted on April 6,1989, using recorder IR-56-2R605 to demonstrate HPCI operability. The inspector reviewed the test data and had no questions. This item is closed.
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3.3 Three Mile Island Action Plan Items
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(Closed) II.D.1 Items 2 and 3, Performance Testing of Boiling Water Reactor / pressurized Water Reactor Relief and Safety Valves l
This item required the licensee to conduct testing to qualify the
reactor coolant system relief and safety valves under expected
operating conditions for design-basis transients and accidents.
In section 5.2.2 of the FSAR, NRC concluded that the pressure relief system, in conjunction with the reactor protection. system, will provide adequate protection against overpressurization of the reactor coolant pressure boundary.
To satisfy the testing requirements, the licensee participated in the BWR Owners Group program to test safety relief valves. The test program is documented in topical report NEDE-24988 P/NEDO-24988 and its applicability to the licensee is discussed in Appendix A to that report. The test results demonstrate that the licensee's relief and-safety valves will adequately perform their intended function under the expected operating conditions of design-basis transients and accidents. The licensee sent its Steam Relief Valves (SRVs) to Target Rock for implementation of GE SIL 196 through supplement 14 and the valves have subsequently been returned.
Item 3 discussed qualification of PWR block valves and is not applicable to the licensee.
SRV 2FD13h has been removed for lift check under MRF 8905253 because it was last tested July 2, 1984 and exceeded PECo's 60 month criteria.
Section 7 of preoperational test 2P83.1 (MSRV) was also reviewed.
Based on the above this item is closed.
3.4 NRC Bulletin Closecut a.
Closed) Bulletin (50-353/78-BU-14) Buna-N Components in ASCo Solenoid Valves. This bulletin ' elated to failures of control rods to insert on a scram due to degradation, of Buna-N diaphrams in the scram pilot valves.
GESIL 128, Rev. 1 Supp 1 indicates that the Buna-N parts have a seven year combined shelf and in-service life when referenced to the packaging date on the rebuild kit.
The inspector reviewed draft Revision 7 to PM2-600-036 Preventive Maintenance Procedure of Hydraulic Control Units (HCU).
Prerequisite 4.2 will require verification of adequate remaining service life for Buna-N components, as will a note on Appendix 2, Spare Parts Checkoff List. This item is close {
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(Closed) Bulletin (50-353/88-BU-05') This bulletin was issued in May 1985, and. required licensees to take-action to assure the
. acceptability of-materials supplied by Piping Supplies.
Incorporated and West Jersey Manufacturing.
Supplement 2 to the bulletin, issued in August 1988, suspended actions for operating units, but required continuation of-' effort for.
construction sites.
Site activities were reviewed previously in IR-50-353/88-21.
NRC has now completed its review of the PECo submittal for' Unit 2, and has accepted it by letter dated
' June 20,-1989. This issue is closed for Unit-2, but remains open for. Unit 1.
'4.0 Surveillance /Special Test Observations (61726, 64704)
During' this inspection period, the inspector reviewed in progress surveillance testing as well as completed surveillance packages. The inspector verified:that' surveillance were performed in accordance with licensee approved procedures and NRC regulations.
The inspector also verified that instruments.used were within' calibration tolerances and that qualified technicians-performed the surveillance.
In addition, for Unit 2 the inspector verified the adequacy of the licensee's tracking mechanism for assuring that required surveillance tests required for fuel load were complete.
The following surveillance were reviewed:
Unit 1 SP-5-064 Procedure to Verify Vacuum Relief Valve PSV-057-137D-1 Operation ST-3-047-320-1 SDV Operability on Scram
.ST-3-047-321-1 Backup Scram Valves Refueling Operation Test
- ST-3-047-790-1 CRD Accumulator Check Valve Timing Test ST-3-048-230-1 SLC Pump, Valve, and Flow Test-ST-3-048-320-1 SLC Operability ST-3-074-500-1 Calibration and Return to Service of LPRM's
- ST-3-097-350-0 Annual Inventory of Special Nuclear Material
- ST-3-107-800-1 Control Rod density comparison ST-6-060-076-1 Suppression Pool /Drywell Vacuum Breaker Valve Cycling Test 4.1 Completed tests for the asterisked procedures were reviewed in greater detail.
No concerns were identified with the annual inventory or control rod density tests.
However, the inspector had concerns with the implementation of technical specification surveillance requirements for control rod scram accumulators.
These scram accumulators provide a source of kinetic energy to insert control rods and stop the chain reaction in the event that reactor pressure is low. The design is such that there is adequate water caracity in the accumulator to complete CRD scram stroke within the I
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25 required' time at startup or lower' reactor pressure. A ball. check valve (115) in the charging water. riser retains the water in the accumulator for a limited time in the event that supply pressure fails and prevents backflow from the. scram accumulator.
When the reactor is at elevated pressure (above 500 psig) the control rods will scram on reactor pressure alone. Technical Specification paragraph 4.1.3.5.b.2. states that each control rod scram accumulator shall be determined operable at least once per 18 months by' measuring and recording the time for up to 10 minutes that each individual. accumulator check valve maintains the associated accumulator pressure above the alarm setpoint with no control rod drive pump operating. 'ST-3-047-790-1, CDR Accumulator Check Valve Timing test, implements the requirements of T.S. 4.1.3.5.b.2.
The test as_ written requires tripping,the operating CRD pump, with all'
accumulators above the alarm setpoint-(given as 970 psi) and recording the accumulators that alarm dur$ng-the 10 minute period.
The test acceptance criteria is given as recording the accumulators that alarm during the 10 minute time period. There appears to be little control. over the accumulator pressure at the start of the test,. so that a small or large leak could :l ve the alarm, depending i
upon the starting pressure.
This makes tert results difficult to reproduce. The test as written required no actions to correct leaking ball check valves and apparently none was taken. The licensee saw no need for corrective maintenance nor did they consider the ' accumulator'or associated control rod inoperable. The inspector noted that HCU ball check valve leakage at another licensee facility-had caused Peach Bottom to write a surveillance test to test and repair any ball check valves that do not meet specified criteria.
The inspector was concerned with the apparent lack of attention this industry experience feed back had at Limerick. A review of all 6 completed" tests showed the following results:
Number of accumu-lators that failed Number of Date of test to maintain pressure.
Repeat Failures 09/11/84
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05/04/86
4 (3 failed all 3 tests)
08/19/87
5 (3 failed all 4 tests)
(1 failed 3 tests)
01/13/89
9 (3 failed all 5 tests)
(1 failed 4 tests)
(1 failed 3 tests)
(4 failed 2 tests)
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7 (3 failed all 6 tests)
(1 failed 5 tests)
(2 failed 3 tests)
(1 failed 2 tests)
For the test performed on May 9, 1989 four of the failed accumulators are for adjacent control rods in the middle of the core. The ball check valves (115) serve to keep the scram accumulators charged in the event CRD pumps are not available.
l During reactor startup or at low reactor pressure the control red
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drives with excessive accumulator leakage could have failed to scram I
if a CRD pump were unavailable.
Failure to declare the control rod scram accumulator inoperable after they failed to maintain pressure above the alarm setpoint is a violation of T.S. 4.1.3.5.b.2.
(50-352/89-12-03)
In addition failure to take corrective action or recognize the need for corrective action is a concern. The inspector noted that there were numerous plant conditions where these recognized discrepancies could have been repaired.
The inspector also noted that procedure ON-107, Control Rod Drive System Problems, requires the cperator to scram the reactor if more than 1 CRD scram accumulator is inoperable and the CRD pump is not running.
Because of the alternate method of scramming the control rods the licensee was granted a temporary waiver of compliance from the technical specification requirement on June 9, 1989 by NRR to allow continued power operation.
4.2 ST-1-11-251-0 Emergency Service Water (ESW) Loop ' A' Flow Balance This test was performed to verify that design flow rates were established to the ESW Loop 'A'
components.
The validity of the original flow balance test data was questioned when the total system flow indication did not correlate with the sum of the individual component flews.
Licensee investigations revealed that fouling of some of the components had occurred between the time that flow vs I
differential pressure (d/p) curves were developed and the performar,ce of the initial flow balance. As a result, ST-1-11-251-0 was developed to reperform the loop 'A' flow balance following component cleaning.
The results of the test were satisfactory (with several somponents receiving minimum flows) and a routine test is being developed which will monitor component flows on a monthly basis to detect fouling.
The inspector had no further questions at this time.
5.0
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Maintenance Observations (62703)
l The inspector reviewed the following safety related maintenance activities to verify that repairs were made in accordance with approved procedures, and in compliance with NRC regulations and
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recognized codes and standards. The inspector also verified that
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the replacement parts and quality control utilized on the repairs were in compliance with the licensee's QA program.
5.1 Unit 1 Vacuum Breaker Troubleshooting 6.0 Review of Periodic and Special Reports (90713)
Upon receipt, the inspector reviewed periodic and special reports. The review included the following:
inclusion of information required by the NRC; test results and/or supporting information consistent with design predictions and performance specifications; planned corrective action for resolution of problems, and deportability and validity of report information.
The following periodic report was reviewed:
Monthly Operating Report - May, 1989 The inspector had no questions regarding this report.
7.0 Licensee Event Report Followuo (90712, 92700)
The inspector reviewed the following LERs to determine that deportability requirements were fulfilled, that immediate corrective action was taken, and that corrective action to prevent recurrence was accomplished in accordance with technical specifications.
7.1 Unit 1 LER 89-11. This report was submitted as a voluntary report and documented the local leak rate test results for the main steam isolation valves (MSIVs). This testing was performed during the second refueling outage. The test data shows that the 'D'
MSIV combined leakage was in excess of the technical specification value of 11.5 standard cubic feet per hour (SCFH) and in fact the flow indicator went offscale (greater than 317.8 SCFH).
Valve maintenance was performed and was successful in reducing leakage below the 11.5 SCFM specification.
The inspector has requested additional information to clarify why this was a voluntary report in lieu of a required 30 day report per 10 CFR 50.73. Also an evaluation of the significance a leak rate of this magnitude was requested.
This additional information will be reviewed in a future report.
LER 89-30. This LER reported a Technical Specification violation which occurred when a milk sampling station was no longer available to provide samples per the Radiological Environmental Monitoring Program and the Replacement Samples did not meet the Technical i
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Specification for being the high dose locations. A new milk sample
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station has been located to remedy this condition. The inspector i
had no_further questions regarding this report.
l LER 89-31.
This LER reported a manual control room ventilation i
isolation which was initiated when an operator detected a wintergreen scent indicating the possible intrusion of carbon dioxide into the atmosphere.
Investigations revealed the scent was
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due to residual oil of wintergreen from previous fire protection system testing and in fact the atmosphere was satisfactory.
The operator actions necessary to correctly respond to such an event were not clear and thus procedure revisions are being implemented.
The inspector had no further quer,tions regarding this event.
LER 89-032.
This LER reported a reactor scram which occurred with the reactor shut down and all control rods fully inserted. The cause was an inadequate surveillance test procedure which was subsequently corrected. The inspector had no further questions regarding this report.
LER 89-033. This LER reported a reactor water cleanup system isolation which was due to system valve leakage which resulted in a high differential flow isolation signal.
Two valves have been repaired and the third will be repaired when conditions permit. The inspector had nc, further questions regarding this event.
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Unit 1 LERs88-031, 89-02, 89-12,89-023 addressed fire protection issues and are discussed in Section 3.1.
l 8.0 Assurance of Quality 8.1 Unit 1 Additional examples of failure to follow procedures on the part of plant personnel were identified. These examples along with those cited in reports 50-352/88-09 and 50-352/88-10 indicate an area of declining performance.
(Section 2.1.3.2)
The performance of the HCU check valve leaking test without utilizing the test results to evaluate component operability (or to schedule corrective maintenance) displayed a lack of appreciation of the safety significance of the surveillance test program.
(See Section 4.1)
8.2 Unit 2 There appears to be a possible weakness in the licensee's review and approval process for Startup Tests Procedures as exhibited by the fact that STP-5.6, Rated Reactor Pressure Scram Testing, Revision 1, was issued without appropriate modifications to the procedure to reflect changes in plant conditions.
(Section 2.2.3.2)
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9.0 Exit Interview (30703)
The NRC_ resident inspectors discussed the issues in this report throughout the inspection period, and summarized the findings at an ex ?t -
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ATTACHMENT A Administrative and Startup Test Procedures Reviewed Limerick Generation Station (73S) A-200, Startup Test Procedure Format and Content, Revision 3.
LGS A-201, Startup Test Procedure Control, Revision 4.
LGS A-202, Startup Test Implemt tation, Revision 8.
LGS A-203, Startup Test Program Personnel Training and Qualification, Revision 2.
Startup Test Procedure (STP) - 3.0, Fuel Loading - Main Body, Revision 1, June 7, 1989.
STP-3.1, Fuel Load, Revision 1 June 7,1989.
STP-5.0, Control Rod Drive System - Main Body, Revision 1, June 7,1989.
STP-5.1, Insert-Withdrawal Checks, Revision 1, June 7, 1989.
STP-5.2, Zero Reactor Pressure Friction Testing, Revision 1, June 7, 1989.
STP-5.3, Zero Reactor Pressure Scram Testing, Revision 1, June 7,1989.
STP-5.4, Scram Testing of Selected Rods, Revision 1, June 7, 1989.
STP-5.5, Rated Reactor Pressure Friction Testing, Revision 0, March 27, 1989 STP-5.6, Rated Reactor Pressure Scram Testing, Revision 1, June 7, 1989.
STP-5.7, Rated Reactor Pressure Insert / Withdraw Checks and Scram Testing of Selected Rods, Revision 0, March 27, 1989 STP-5.8, Scram Timing of Selected Rods Durir.g Planned Scrams of the Startup Test Program, Revision 0, March 27,1989 STP-13.0, Process Computer-Main Body, Revision 0, March 29, 1989 STP-13.1, Static System Test Case, Revision 0, March 29, 1989 STP-14.6, RCIC Cold Quick Start at Rated Pressure - CST to RPV, Revision 0, February 17, 1989.
STP-17.0, System Expansion - Main Body, Revisicn 1, May 11, 1989.
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STP-17.1, Measured Pipe Displacements.
(Selected B0P Systems), Revision 1, May 11, 1989 STP-17.2, Measured Pipe Displacement (Feedwater System), Revision 0, March 31, 1989.
STP-17.3, Measured Pipe Displacements (Main Steam Inside Drywell and Reactor Recirc), Revision 0, March 31, 1989.
ST-17.4, Visual Pipe Inspection (Main Steam Inside Drywell and Reactor Recirc), Revi; ion 0, March 31, 1989.
STP-27.2, Bypass Valves Capacity Check, Revision 0, January 17, 1989.
STP-99.0, Master Startup Test Procedure - Main Body, Revision 1, June 7, 1989.
STP-99.1, Test Phase II - Initial Fuel Loading and Zero Power Testing, Revision 1, June 7,1989.
STP-99.2, Test Phase III - Low Power Testing, Revis'on 1, June 7, 1989.
STP-99.3, Test Plateau A - Test Condition 1, Revision 1, June 7.,1989.
STP-99.4, Test Plateau B - Test Condition 2, Revision 0, March 29, 1989.
STP-99.5, Test Plateau C - Test Condition 3, Revision 0, March 29, 1989.
STP-99.6, Test Plateau D - 100?J Rod Line Testing, Revision 1, June 7,1989.
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l ATTACHMENT B References Regulatory Guide 1.68, Revision 2, August 1978, " Initial Test Program for Water Cooled Nuclear Power Plant" ANSI N18.7-1976, " Administrative Controls and Quality Assurance for Operations Phase of Nuclear Power Plants."
Limerick Generating Station Unit 2, Technical Specifications, June 22, 1989.
Limerick Generating Station Unit 2, Final Safety Analysis Report (FSAR),
Chapter 14 " Initial Test Program."
GE Specifications, NEB 0 23A1918, Revision 3, "Startup Te:t Specification, Limerick Units 1 and 2."
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