ML20083L910
| ML20083L910 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 07/28/1994 |
| From: | Horn G NEBRASKA PUBLIC POWER DISTRICT |
| To: | Callan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| Shared Package | |
| ML20083L862 | List: |
| References | |
| CAL, NLS940001, NUDOCS 9505190039 | |
| Download: ML20083L910 (21) | |
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A COOPER NUCLEAR STATEW P.O. BOX 98. BROWNVLLE, NEBAAEA 68321 Nebraska Public Power District *WAE""
NLS940001 July 28, 1994
)
1 Mr. L. J. Callan Regional Administrator {
{
FRC Region IV '
611 Ryan Plaza Drive Suite 400 Arlington, Texas 76011
Subject:
Response to Confirmatory Action Letter Cooper Nuclear Station NRC Docket No. 50-298
References:
(1) Confirmatory Action Letter (Revision 0) Dated May 27, 1994, to Guy R. Horn - Nebraska Public Power District (CAL 4-94-06).
i (2) ConfirTnatory Action Letter (Revision 1) Dated June 16, 1994, to Guy R. Horn -
Nebraska Public Power District (CAL 4-94-06A).
(3) Confirmatory Action Letter (Revision 2) Dated July 1,1994, to Guy R. Horn - Nebraska Public Power District (CAL 4-94-06B).
Dear Mr. Callan:
References (1), (2), and (3) confirmed Nebraska Public Power District's (the h District's) commitment to address four items prior to restart of the Cooper
' Nuclear Station (CNS). Several technical meetings already have been held which addressed NRC concerns described in the Confirmatory Action Letter (CAL) Items 1, 2, 3, and 4. These items involved: 1) as-found testing of 4160- and 480-volt undervoltage devices; 2) the design basis for surveillance acceptance criteria for the Control Room and Turbine Building Ventilation Systems; 3) ' primary containment penetration discrepancies; and, 4) electrical distribution surveillance testing and inservice inspection of penetration welds. An additional meeting will be held in NRC Headquarters office to review: 1) the conclusions discussed during the four technical meetings noted above; 2) actions taken to resolve the noted issues; and, 3) the basis for District management's conclusion that CNS is ready for restart. That meeting has been scheduled for July 29, 1994, at 9:00 a.m.
CAL Item 5 required the District, prior to plant restart, to provide the NRC.
Region IV office with a letter discussing eight areas of NRC interest. The attached discussion responds to this NRC request. However, limiting this response to just answering NRC questions would not fully capture the extensive ef forts that the District has expended to address not wly NRC issues, but also issues that CNS management has determined must be resolved prior to plant startup. During this shutdown, CNS has assessed several areas of Technical Specification interpretation, system design basis requirements, maintenance 9505190039 950512 -
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I WLS940001 July.28, 1994 Page 2 practices, and management oversight. Additionally, several CNS ef forts resulted in' extension of the shutdown period because District management took a careful' and conservative approach to resolving these emerging issues. Region IV management has been kept apprised of the District's actions.
The District's findings, while having a negative connotation ~ regarding compliance, also have a positive side. Recent findings are in great part a result of management ef forts to improve the questioning attitude of personnel and 4
management's commitment to resolving emerging. issues. CNS culture improvement initiatives to identify and fix problems correctly the first time are working.
New management has brought to CNS fresh ideas and higher standards for problem identification and resolution. Issues are being raised and resolved which, in past years, may have been placed at a lower priority. District management firmly believes that these initiatives will result in sustained improvement for the long term. The District will continue to monitor the effectiveness of performance improvement efforts to ensure that desired results are being achieved. The NRC will be kept informed of the progress of performance improvement efforts.
If there are any questions about the information presented in the attachment, or on other mattera, please call.
Sin rely
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G R. Horn Vi resident, Nuclear
/nr Attachiaent cc: U.S. Nuclear Regulatory Commission Attention: Document Control Desk I l
NRC Resident Inspector Office Cooper Nuclear Station i NPG Distribution a i i
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'D 71S940001 July 28, 1994 j Attachment l Introduction l
CAL 4-94-06B, Item 5, required that prior to restart, the District provide Region IV with a letter that discusses the following
, (a) the root cause(s) for defeating the undervoltage trip function in the !
Motor Control Center N supply breaker; (b) the actions taken to confirm the design basis for the Control Room and p Turbine Building Ventilation Systems; (c) the results of all testing that was performed for the issues discussed in Items 1, 2, and 3 of the CAL; e (d) the safety significance of all of f-normal or discrepant conditions in Items 1, 2, 3, and 4 of the CAL; (e) the corrective actions that will be taken to prevent recurrence of the installation of devices (i.e., cable ties, jumpers, blocks, etc.) that will prevent the actuation of safety system functions and to ensure that the design basis surveillance testing criteria are established and maintained for the facility; (f) the lessons learned by CNS staf f in response to the incident involving the ;
undervoltage trip function in the motor control center supply breakers, (
including the lack of prompt recognition of the potential safety t significance; (g) the basis fer the %trict's determination that the testing programs for Electrical Distribution System surveillance testing and inservice inspection of penetration welds are technically adequate and complete; and, (h) the basis for the District's assurance that the testing programs for other licensed activities are-adequately implemented.
Each of these CAL issues are addressed in this attachment. Where appropriate, the District also has addressed previously ongoing activities that are responsive to NRC concerns and additional issues that have emerged as a result of initial problem investigations.
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Page 1 of 19
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- NLS940001 \
July 28, 1994 Attachment CAL 4-94-06b Item 5 (a) -
" Discuss the root cause(s) for defeating the undervoltage trip function in the Motor Control Center N supply breaker. "
NPPD Rescanse on May 16,1994, a cable tie was found installed on the undervoltage trip device for the 480-volt feeder _ breaker to MCC-N. Its installation defeated this undervoltage trip device which' was installed to isolate (shed) its load in the event of Loss of Off Site Power.
The root cause of the event is the failure of management to ensure that require:nonts for configuration control were not adequately implemented into the maintenance procedure. Maintenance procedures must have appropriate configuration control elements. Management's expectations must be clearly communicated and effected through the procedure review and ;
approval process. While procedure content guidance existed regarding this issue, it was not well expressed. Strong, clear management expectations regarding its inclusion in maintenance procedures was not provided.
The immediate cause of the loss of configuration control was found to be an inadequate maintenance procedure. The procedure allowed installation of a cable tie, but did not provide specific guidance to remove, or verify removal, of the cable tie. While not the root cause, post-maintenance testing and surveillance tests both failed to identify that the cable tie was still installed and that the breaker could not perform its intended safety function. Human error also was involved. However, it was only a ,
symptom and not the root Cause. I CAL 4-94-06b .
Item 5 (b) s
" Discuss the actions taken to confirm the design basis for the control Room and Turbine Building Ventilation Systems. "
NPPD Response The District has reviewed several hundred documents to verify the design 'i basis for the control Room and Turbine Building Ventilation Systems. ;
These documents span nearly 30 years, beginning with pre-construction in ;
the mid 1960's, through the present. The documents reviewed included General Electric plant design criteria; Burns and Roe calculations, system descriptions and correspondence; pre-operational test procedures and test results; the FSAR and related amendments, questions and answers; the SER; the USAR; correspondence with the NRC; internal NPPD correspondence; test procedures, design changes and supporting calculations.
The results of our review are as follows:
Page 2 of 19
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i NLS940001 July 28, 1994
- Attachment control Room Ventilation System Desian Basis The Control Room Ventilation System design basis is:
a) Provide . temperature and humidity control and air movement for personnel comfort and optimum equipment performance, b) Provide sufficient filtered fresh air supply for personnel.
c) Minimize the possibility of exhaust air recirculation into the air intake.
d) Provide for operator protection in the event of a Design Basis Accident by providing filtered air and maintaining the Control Room Envelope at a positive pressure with respect to adjacent areas.
This function is performed by the Control Room Emergency Filter System. Dose calculations assume a positive pressure in the control Room Envelope; however, no specific value of pressure is assumed for use in the calculations. Dose calculations assume 10 CFM of unfiltered inleakage in accordance with guidance furnished by Murphy and Campe in a paper titled, " Nuclear Power Plant Control Room Ventilation System Design for Meeting General Criterion 19."
The Control Room Ventilation System is not designed to automatically respond to toxic gas events; rather, operators don Self contained Breathing Apparatus (SCBA) and manually secure the outside air supply to the Control Room. .;
The administrative, operability, and surveillance requirements for the Control Room Emergency Filter System were discussed during a meeting between NPPD and NRC on July 7, 1994, and confirmed in a letter to the NRC from G. R. Horn, dated July 20, 1994.
Turbine Buildina Ventilation System Desian Basis The Turbine Building Ventilation System design basis is:
a) Provide temperature control and air movement for personnel comfort and optimum equipment performance.
b) Provide sufficient filtered fresh air supply for personnel.
c) Provide for air movement from lesser to progressively greater areas of radioactive contamination potential prior to final exhaust.
d) Minimize the possibility of exhaust air recirculation into the air intake.
e) Accommodate effluent monitoring capability.
Page 3 of 19 4
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NLS940001 July 28, 1994 Attachment CAL 4-94-06b Item 5 (c)1:
- " Discuss the results of all testing that was perfomed for the issue discussed in Item 1 of the CAL
l 4160-volt undervoltage relay logic and 480-volt undervoltage devices (a s-found) . " i NPPD Response 4160-Volt Testinc As-found testing of the 4160-volt undervoltage devices for electrical loads supplied directly from the two emergency busses IF and 1G was performed. Two discrepancies were identified. The discrepancies consisted of one relay that exceeded the allowable time delay setting and one relay contact that had marginally high resistance. Retests following resetting of the relay timing and cleaning of the contacts were satisfactory.
480-Volt Testina Out of a total of 12 breakers that were as-found tested, two breakers failed to trip and two breakers failed to trip within the time delay acceptance criteria. Subsequent testing of the unciarvoltage trip assemblies (UVTAs) identified a fif th breaker which previously passed its acceptance testing but failed due to slow actuation timing. The unreliable and inconsistent performance of these UVTAs was either caused by mechanical binding in the latching mechanism or a defect in the time delay attachment. As a result, the UVTAs for these twelve breakers were replaced with a shunt trip device that is activated by the loss of voltage logic for the 4160-volt breakers. Successful testing of this shunt trip network for the 400-volt bus loads was completed on July 4, 1994.
CAL 4-94-06b Item 5 (c)2:
" Discuss the results of all testing that was perfomed for the issue discussed in Item 2 of the CAL:
Control Room and Turbine Building Ventilation Systems. "
NPPD Response pontrol Room Enveloce On April 11, 1994 the Control Room Emergency Bypass Filter System failed post-maintenance testing which was being performed following maintenance on a door that formed part of the Control Room pressurization boundary.
(See LER 94-006, dated May 11, 1994) Several leak pathways were sealed and the Control Room Envelope was successfully tested on April 28, 1994.
Page 4 of 19
m NLS940001 July 28, 1994 Attachment On June 24, 1994 another test of the Control Room Envelope was conducted. ,
to verify that the new administrative limit (a +0.04" wg) could be satisfied. The test. failed. Another search for new or degrading leak paths was conducted. Several small leaks were identified and sealed.
Recent testing confirms that the Control Room Emergency Bypass Filter 't System can satisfy its design basis of providing a positive pressure to the Control Room envelope. The administrative limit of 2,+0.04" wg has been consistently achieved during numerous tests of Control Room Envelope integrity conducted since July 9, 1994, with the exception of a test conducted on July 22, 1994, which failed due to a flow balancing deficiency. The balancing deficiency has been corrected and appropriate Control Room Envelope testing was satisfactorily performed on. July 27, 1994. ,
The effects of wind speed have also been considered during recent testing and will be considered during future testing. Investigation into system '
design improvements to increase system performance margins is continuing.
These improvements will be implemented prior to startup from the spring 1995 refueling outage.
Turbine Buildinct
' Actions taken recently to correct operational deficiencies in the Turbine Building Ventilation System discovered following the unsatisfactory Control Room Emergency Bypass Filter System test conducted on April 11, 1994, include the following:
a) Repaired exhaust fan vortex and outlet dampers and' controls, b) Cleaned and lubricated the vortex dampers for the exhaust fan.
l c) Repaired damaged ductwork. ;
i d) Verified sensing line integrity.
e) Cleaned and balanced the system to obtain -0.25" wg in the Steam Jet i Air Ejector (SJAE) Room at design flow.
f) Updated the system operating procedure to require operation at
-0.25" wg with respect to the environment in the SJAE Room.. This parameter is also routinely logged in the Control Room Data log in the Control Room.
As a result of the above actions, satisfactory system operation at the
-0.25" wg differential pressure margin in the SJAE Room has been demonstrated. Preventive measures will be implemented through the ongoing Preventive Maintenance Program to ensure that performance of the Turbine Building ventilation system will remain satisfactory.
Page 5 of 19 ;
NLS940001 July 28, 1994 Attachment CAL 4-94-06b Item 5 (c)3:
" Discuss the results of all testing that was perfonned for the issue discussed in Item 3 of the CAL:
Primary Containment Penetrations. "
NPPD Response Walkdowns of primary containment penetrations for Design Basis Reconstitution purposes were performed from May 18 through June 5, 1994.
As a result of identified discrepancies, eleven design changes were developed and implemented. These actions included the addition of test connections, installation of welded caps on spare penetrations, complete redesign of several containment isolation barriers, and installation of caps on vents, drain lines and test connections.
As-found testing was performed for penetrations which had not previously been Type A, B, or C tested and for which as-found testing was determined to be practicable. The total as-found leak rate due to these additional tests was approximately 26 SCFH, not including drywell pneumatic supply check valve IA-CV-65CV. Leak rate testing for this check valve revealed that it could not be pressurized. The safety significance of this leak rate is discussed in the response to Issue 5 (d)3. Following modifications and repairs, the total Primary Containment as-left leak rate, including IA-CV-65CV, was less than the 0.6 La (189 SCFH) limit specified in CNS Technical Specifications.
Penetrations classified as IIIN, IVP, or indeterminate, were identified for which appropriate NDE records could not be found to ensure that the piping welds were of equivalent quality level to the containment. A design change was completed on forty-seven penetrations during this outage to upgrade the design and installation of this piping to a quality that is equivalent to the primary containment. The District will update the CNS ASME Section XI Inservice Inspection Program prior to the 1995 outage to include these piping segments. This action will ensure that the quality level of these piping segments will be maintained in the future.
Thirty-five related butt welds were radiographed. of that total, five rejectable indications were found. Two of the five rejected welds were removed by shortening a piping run and the remaining three welds were repaired. In addition, a total of 262 socket welds were subjected to liquid penetrant examination. There were no rejectable indications.
Based on the as-left leak rate, the repair of rejectable NDE indications on butt welds, and no rejectable indications for socket welds, the District concludes that containment integrity satisfies regulatory requirements. This issue was discussed with the NRC on June 27, 1994.
Page 6 of 19
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. HLS940001 I July 28, 1994 Attachment CAL 4-94-06b Item 5 (d)1:
1
- Discuss the safety significance of all off-normal or discrepant conditions found in Item 1 of the CAL:
4160-volt undervoltage relay logic and 480-volt undervoltage devices (as found)."
NPPD Response 4160-Volt Undervoltace Relav Locic The safety significance of the 4160-volt undervoltage relay discrepancies discovered during performance of Special Procedure 94-208 is as follows:
a) EE-REL-27X3/1G timed out at 14.63 seconds, which is 3.63 seconds longer than allowed by acceptance criteria (10 seconds i 10%) . This relay provides a close interlock in the DG breaker EG2 close circuit to prevent breaker closure until the 480-volt switchgear breakers feeding non-essential loads have adequate time to trip. The design basis for the DGs specify that the output breaker of tne DGs must be closed within sixteen seconds from the time of DG actuation to meet the 10CFR, Part 50, Appendix K Analysis. The 14.63 second timing of EE-REL-27X3/1G would not have prevented DG2 from meeting this requirement. Concurrent with relay timing, DG2 would start, reach required speed, and bus load shedding would occur. Since DG2 would have started within the sixteen second limit and relay EE-REL-27X2/1G would have closed within the sixteen second limit, Bus 1G also would have been powered within the required sixteen seconds and the intended safety function would have been satisfied.
b) The resistance of contacts 11-12 of EE-REL-27X/1GB was found to be higher than the acceptance criteria limits. These contacts provide a trip signal to breaker 1GB during a loss of voltage. The trip of breaker 1GB separates Bus 1G from the off-site power supply and allows transfer to the Emergency Transformer, if available. The acceptance criteria is <1 ohm and the resistance of these contacts was measured at 3.1 ohms. The 1 ohm acceptance criteria was chosen as a screening point for contacts requiring further evaluation.
Subsequent review determined that this contact would have been able to perform as designed under all design basis conditions. Based on the above, the as-found contact resistance had minimal safety significance.
c) On June 16, during performance of testing associated with Special Procedure (SP)94-208, a malfunction associated with the 52/IN contact, the breaker position switch, for breaker 1GS occurred af ter the breaker had been racked to the test position to support testing and then racked in. The breaker malfunction was due to mis-adjustment of its guide wheels which resulted in it becoming misaligned as it was racked into its cubicle. The misalignment led to an over-travel in the position switch as the breaker was electrically cycled, which resulted in the breaker malfunction.
Page 7 of 19
NLS940001 July 28, 1994 Attachment To ensure that we thoroughly understood the cause of failure, a l vendor representative was utilized to assist in evaluating the I condition and correcting it. All other safety related breakers of this type have been inspected and no similar conditions were found. ,
l The inoperable status of the breaker did not have an adverse impact on plant safety during the special procedure. Bus 1G had already been declared inoperable and the plant was in Cold Shutdown. The redundant division was available during performance of the special procedure and during repair of the breaker.
During normal operations, breaker 1GS is normally open, and would automatically close upon loss of power from the Normal and Startup Transformers, powering the 1G bus, providing that power is available ,
f rom the Emergency Transformer. Had this malfunction occurred while at power, the effect would have been that the breaker would not have tripped upon loss of power from the Emergency Transformer.
To assess the operability of the breaker during the past operating cycle, a review of the operating history of the breaker was performed. It was determined that in each case where the breaker was racked in and cycled once successfully, the breaker would then operate properly in each subsequent demand. All failures of the breaker to operate properly have occurred on the first cycle of the breaker after it has been racked in.
On July 18, 1993, the 1GS breaker was racked in and was successfully cycled during the transfer to the emergency transformer and back to the startup transformer. No indication of a breaker problem was indicated between the July 18 cycling and the performance of STP 94-208.
In the misaligned condition, the ability of the breaker to perform its function during a seismic event is being evaluated. In the event that the seismic qualification was not affected by the misalignment, this condition would have had no safety significance.
Should the breaker not be found seismically qualified, the safety significance would have been minimal based upon the following discussion.
The sequence of events that would have resulted in an accident scenario of concern is as follows:
a) loss of a portion of the transmission system and normal off-site power (emergency transformer power source remains available);
b) closure of the 1GS breaker, transferring the Division II emergency bus to the emergency transformer; c) loss of the 1GS breaker trip function due to the effects of a seismic event; Page 8 of 19
- ' NLS940001 July 28,'1994 Attachment d) loss of the emergency transformer, de-energizing both 4160-volt busses; and, e) failure of Diesel Generator 1.
Given this sequence, HPCI and RCIC would have been operated in accordance with plant procedures to stabilize the plant. Operator action would be necessary to locally trip the 1GS breaker, permitting breaker EG2 to close, allowing the DG to assume the necessary loads.
400-Volt Undervoltace Devices Due to test failures and demonstrated unreliability of the 480-volt undervoltage trip devices (UVTA) discussed in Item 5 (c)1 above, Nuclear Engineering Design Calculations (NEDC)94-110, " Operability of DG1 With Additional Loads," and NEDC 94-114, " Steady State Operability of DG and ET With Additional Loads," were prepared to assess whether the EDG units >
would satisfy their intended safety function, even_if the UVTAs did not '
function as intended. As a result of these calculations, the District concluded that: 1) the EDGs would not have stalled; 2) EDG capacity would ;
not have been exceeded to the degree that performance would have been adversely impacted; 3) EDG tie breakers would not have tripped; 4) the fuel supply would have been adequate; and, 5) all electric motors supplied by the EDGs would have successfully accelerated to operating speed. In summary, the EDG units would have been able to perform their intended safety function, even if all twelve of the UVTAs failed.
CAL 4-94-06b Item 5 (d)2:
" Discuss the safety significance of all off-normal or discrepant conditions found in Item 2 of the CAL:
Surveillance testing acceptance criteria for the control room and turbine building ventilation systems. "
NPPD Response As previously discussed, the design basis Control Room operator dose calculation assumes 10 CFM of unfiltered inleakage based on positive pressure in the Control Room envelope. Therefore, the safety significance of the failure to achieve a positive pressure was evaluated by calculating i the dose consequences of up to 2000 CFM of unfiltered inleakage. The basis for this assumption and the detailed results of the calculation has i been provided to the NRC by separate letter from G. R. Horn, dated July l 20, 1994. In summary, the resulting dose would be within GDC 19 and l Standard Review Plan (SRP), Section 6.4 limits.
Based on the results of the calculations summarized in the referenced correspondence, the District concludes that the as-found condition of the Control Room envelope had minimal safety significance.
Page 9 of 19
NLS940001 July 28, 1994 Attachment CAL 4-94-06b Item 5 (d)3:
" Discuss the safety significance of all off-normal or discrepant conditions found in Item 3 of the CAL:
Containment penetrations. "
NPPD Response The majority of the containment penetrations that did not comply with design requirements had been successfully tested at design pressure during the primary containment ILRT last performed in 1991. As-found testing was performed for penetrations which had not previously been subjected to ILRT or LLRT test pressure, and for which as-found testing was determined to be practicable. Testing demonstrated that the leak rates were within Technical Specification limits with the exception of the Drywell Pneumatic Supply Check Valve, IA-CV-65CV, in penetration X-22. Type C LLRT testing revealed this penetration could not be pressurized.
Potential off-site and on-site radiological dose consequences due to leakage from penetration X-22 during the 30 days following the accident were evaluated per calculation NEDC 94-154, "Off-site and On-Site Dose Consequences For LLRT Failure of IA-CV-65CV." The results of this calculation are summarized in the following chart.
Scenario: Whole Body Dose Thyroid Dose Whole Body Dose Thyroid Dose (Rem) (Rem) Limits (Rem) Limits (Rem)
- 1) current off-site LocA 7.4 x 10 9.0 x 10" 25 300 Dose (USAR XIV-6.3)
- 2) off-site LocA Dose 4.2 x 10 5.2 x 10
With Additional Leakage from Penetration X-22
- 3) current Design Basis 1.74 11.39 5 30 Control Room LOCA Dose
- 4) control Room Design 4.42 58.51 )
Basis LOCA Dose With l Additional Leakage from Penetration X-22 !
- 5) control Room LOCA Dose 4.42 10.85 With Additional Leakage from Penetration X-22 and j and no sGTS Actuation I Delay Page 10 of 19 l
l 1
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- NLS940001 July 28, 1994 Attachment Off-site doses, considering the additional leakage in Scenario 2, are far below the 10CFR100 limits of 25 Rem whole body and 300 Rem thyroid. For Scenario 4 the Control Room doses exceed the SRP 6.4 limit of 30 Rem thyroid, but are below 10CFR Part 100 limits. However, this scenario reflects conservatisms which go beyond those required by the relevant guidance documents for dose calculations of this type. The more accurate analysis is discussed below.
Scenario 5, which addresses additional leakage with no Standby Gas Treatment System (SGTS) delay, is more accurate in depicting the control Room dose. This case does not consider 90 seconds of unfiltered release from secondary containment prior to SGTS actuation, which 10 assessed in design basis calculations based upon worst case secondary containment valve closure time. The basis for removing this assumption comes from draft NUREG 1465, " Accident Source Term for Light Water Nuclear Power Plants," which indicates that it would take over one hour for fission product radionuclides to begin to exit containment. Therefore, it is a more realistic case to assume that all flow frem secondary containment containing fission products would be filtered thrav@ the Standby Gas Treatment System within this time. Since Control Room dose for the more realjstic Scenario, No. 5, is within GDC 19 and SRP 6.4 limits and the off-site dose would be within 10 CFR Part 100 limits, the safety significance of the inoperable X-22 penetration is minimal.
Additionally, barriers that should realistically mitigate the effects of the aasigned leak rate include two other valves outboard of IA-CV-65CV and the Instrument Air and Nitrogen Systems. However, since these barriers are non-safety related, they were not taken credit for in the analysis described above. The design pressure / temperature for the associated piping is 125 psi /200*F and the piping system operating pressure for both systems is above 100 psi, well in excess of containment design pressure.
These conservatisms provide further assurance that the Control Room operator thyroid dose would be within regulatory limits.
Creation of the postulated release pathway from primary containment requires a failure in the instrument air system piping, both inside and outside containment, concurrent with a DBA LOCA. A Probabilistic Safety Analysis (PSA) was used to estimate the frequency. It was postulated that under accident conditions (large break LOCA resulting in core damage, probability of occurrence 5.54E-08/yr. ) , the line could become a pathway for radionuclides to reach the environment. The probability of a line break outside of containment was assumed to be bounded by the probability of a loss of the Instrument Air System. This probability, including pipe breaks, is conservatively assumed to be 2.58E-04.
Therefore, the frequency of occurrence of this scenario resulting in a release of radionuclides outside of containment through this penetration to the environment is 1.43E-11/yr. This value is well below the regulatory concern value of 1.0E-07/yr used in Probabilistic Safety Assessments for containment bypass events. Based on the above considerations, containment penetration leak pathways had minimal safety significance.
Page 11 of 19
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NLS940001 July 28, 1994 Attachment CAL 4-94-0Eb Item 5 (d)4.a:
" Discuss the safety significance of all off-normal or discrepant conditions found in item 4 of the CAL:
Electrical distribution system surveillance. "
NPPD Response A review of the Electrical Distribution System was conducted to verify testing was performed as specified in the Technical Specifications, USAR, and Design Basis. This review identified two discrepancies with potential safety concerns which are discussed below:
a) Relays 27/1F-1 and 27/1G-1 were not being tested properly per the definition of the instrument functional test. The monthly functional test visually verified contact closure; however, the Technical Specification definition required the associated auxiliary ;
relay to be energized. The past method of functionally testing the l relay was not a safety concern because:
- 1) Relays 27/1F-1 and 27/1G-1 are calibration tested once per cycle and functionally tested once per cycle by surveillance l
Procedure 6.3.4.3. j l
- 2) The subject relays are protective relays which have contact l mechanisms in which the relay contact position is visible in I the both the open and close conditions. In the test mode, the l relay contact will not be in the intermediate position. ,
1 1
- 3) The monthly functional check did prove the induction disk !
rotated when the input voltage was removed, indicating a loss of voltage had been detected by the relay mechanism.
The monthly surveillance procedure has since been revised to correct this discrepancy and the relays have been satisfactorily tested.
b) Two installed Diesel Generator Starting Air pressure indicators for which qualification was in question were discovered. An engineering evaluation was performed which verified that the instruments were qualifiable and capable of performing their safety function.
Documentation of their qualification has now been developed.
Therefore, the safety significance of this discrepancy was minimal.
Page 12 of 19
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NLS940001 July 28, 1994 Attachment CAL 4-94-06b Item 5 (d)4.b:
" Discuss the safety significance of all off-normal or discrepant conditions found in Item 4 of the CAL:
Inservice inspection of penetraeion welds. "
NPPD Response Twelve Class 2 welds were found to have been excluded from the ISI Program. However, even with the addition of the twelve welds to the total Class 2 weld population, the required weld examination percentages are 1 still satisfied. For the current ten year interval, one outage remains to complete inspection interval examination requirements. CNS is confident that the welds are mechanically sound based on NDE verification at original construction. As such, the District has concluded that the safety significance of excluding the 12 Class 2 welds from the ISI Program is minimal. Further information related to this issue is provided in the response to CAL Item 5 (g) .
CAL 4-94-06b Item 5 (d)4c:
" Discuss the safety significance of all off-normal or discrepant conditions found in Item 4 of the CAL:
Testing programs implemented in other areas of licensed activities. "
NPPD Response The safety significance associated with ongoing testing programs implemented in other areas of licensed activities is addressed in the response to Item 5(h).
CAL 4-94-06b Item 5 (ell:
" Discuss the corrective actions that will be taken to:
Prevent recurrence of the installation of devices (i . e . , tie wraps, jumpers, blocks, etc.) that will prevent the actuation of safety-system functions."
NPPD Response The following corrective actions have been or will be taken:
a) A walkdown was conducted to verify that no similar cable tie installations were in place. None were found.
b) A review was performed of station mechanical and electrical maintenance procedures; surveillance procedures in the chemistry, operations, and instrument and control areas, as well as the Page 13 of 19
e d NLS940001 July 28, 1994 Attachment 14.x series instrument and control procedures, to identify similar procedural deficiencies. Three mechanical procedures were identified as deficient. Changes have been initiated to correct them. Fifteen electrical procedural deficiencies were identified.
Changes have been initiated to correct them. Three minor discrepancies were identified and corrected in the operations and instrument and control procedures. The noted procedure discrepancies will be corrected and approved prior to next use. No discrepancies were identified in the chemistry procedures. Field walkdowns were performed for similar deficiencies that could have been created during past use of the deficient procedures. No equipment configuration discrepancies were found.
c) A revision has been made to Maintenance Work Practice (MWP) 5.0.4 to add guidance to further ensure that any impairments, changes, or blocking devices installed during performance of maintenance have been removed prior to completion of the procedure.
d) In response to management deficiencies, maintenance supervision has held meetings with their personnel to emphasize the need for procedure compliance and immediate correction of problems and incomplete understanding of procedure requirements. Considerable effort is also being expended by Maintenance Management to ensure that expectations are clear regarding procedure compliance, procedure adequacy, and control of maintenance activities.
CAL 4-94-06b Item 5 (e) 2 :
" Discuss the corrective actions that will be taken to ensure that the design basis surveillance testing criteria are established and maintained for the facility. "
NPPD Response l
The testing requirements specified in Technical Specifications and the USAR for the major components of six critical systems have been reviewed against existing surveillance procedures. The systems reviewed included:
High Pressure Coolant Injection Reactor Core Isolation Cooling Residual Heat Removal (Low Pressure Coolant Injection mode)
Core Spray Automatic Depressurization Emergency Diesel Generators The review was performed as follows:
a) An existing cross reference between Technical Specifications and surveillance procedures, which is maintained by the Surveillance Coordinator, was independently reviewed for correctness.
Page 14 of 19
NLS940001 July 28, 1994 Attachment b) The Technical Specification surveillance requirements were reviewed against f.he respective surveillance procedures to determine if the requiremtnts were being met.
c) USAR stecions. describing the six systems were reviewed to determine if the USAR requirements were being met by the surveillance.
The results of this review are summarized in the response to Item 5(h) .
Also, the District will verify that operating and surveillance test procedure content and surveillance test acceptance criteria are consistent with the design basis. Verification of surveillance testing program adequacy will be accomplished for future system-related Design Criteria Documents (DCDs) as part of the Design Basis Reconstitution Project.
Based upon a risk assessment, management has selected those systems that will be completed on an expeditious basis.
An in-depth systematic review of the surveillance test program was initiated on July, 11 1994. This review addresses testing requirements specified in the Technical Specifications, the USAR, and those completed DCDs to ensure that the surveillance test procedures, including those specifically developed for ASME IST purposes, adequately incorporate pertinent requirements. This review is scheduled to be completed by March 1995. The systems included in the scope of this review are those for which Technical Specification testing requirements are specified.
Organizational and programmatic changes will be made to enhance ,
configuration control consistency between design input and design output i documents to ensure that: 1) procedure modifications are reviewed for impact on design input documents; 2) design output documents are revised when affected by changec to calculations; and, 3) changes to CNS engineering program documents (e.g., LLRT) are reviewed for impact on design input documents. Ac'ditionally, the District will perform a review to identify additional design input and output documents that require enhanced configuration naintenance provisions, CAL 4-94-06b Item 5 (f) -
" Discuss the lessons learned by the Cooper Nuclear Station staff in response to the incident involving the undervoltage trip function in the motor control center supply breaker, including the lack of prompt recognition of the potential safety significance of some issues. "
NPPD Response An assessment was performed of CNS performance related to the noted incident. The District found that the initial response was narrow, compliance-based, and poorly directed by management. Management and staff exhibited narrow-focused and compliance-based values. Although the District has been striving to provide the tools and management oversight to overcome those behaviors, it is clear that efforts have not yet been successful.
Page 15 of 19
l 4 NLS940001
< l July 28, 1994 l
Attachment I
Management performance issues are being addressed in great part by chaages in management staff, communicating management expectations, and requiring an increased level of accountability. The District's immediate goal is to acquire new talent with higher performance standards, to deepen management resources, and to allow reassignment of some incumbent managers to other areas of need, while bringing fresh industry perspective to Cooper Nuclear i Station's central management structure. A new Site Manager and Licensing '
Manager, both from plants which recently improved their performance, assumed their duties on July 11. The Maintenance Manager has been replaced from within. A new senior manager with many years in the Navy Nuclear Program has been hired. A new Corrective Action Program Manager has been assigned, Condition Resolution Team mentor support has been provided, and five full-time, rotational Condition Resolution Team Leader positions are being established. Additional planning is underway for repiecement or reassignment of the other key senior and middle manager positions, as appropriate.
Weaknesses in Quality Assurance staff performance during recent events are being addressed by: 1) the establishment of stronger guidance for dealing with emerging issues and interaction with the line organization; 2) increased oversight and supervision of QA field activities by QA Division and Department Managers, 3) training to improve safety and assessment skills (underway and to be completed by August 1994); and, 4) publication of senior management expectations for quality assessment activities.
/
Management oversight of Condition Review Group (CRG) activities has been increased by having a senior manager oversee the CRG's evaluation and decision making activities in the role of a protagonist to ensure adequate rigor and urgency. Condition Reports are being more thoroughly screened for significance by the Technical Staff prior to submittal to the CRG.
To improve safety attitudes and performance, training in safety principles and performance-based evaluation techniques will be provided to appropriate segments of the NPG staff starting in September 1994.
Advanced root cause analysis and investigation training will also be provided.
Other programs were found to be ineffective during recent events. For example, the Operating Experience Review (OER) program should have addressed the inadequate diesel load shed testing and logic system functional testing problems. To ensure that this deficiency is . not pervasive, a comprehensive review of past operating experience documents has begun.
The absence of design basis infomation adversely affected the District's efficiency in responding to potential safety issues. As a result, the reconstitution schedule has been accelerated. Efforts to review and upgrade the CNS surveillance and other testing programs are discussed elsewhere in this letter.
In summary, the District has taken, and will continue to take actions responsive to technical, programmatic, and managerial problems as they are identified.
Page 16 of 19
NLS940001 July 28, 1994 Attachment CAL 4-94-06b Item 5 (a) -
" Discuss the basis for your determination that the testing programs for electrical distribution system surveillance testing and inservf.ce inspection of penetration welds are technically adequate and complace. "
NPPD Response Electrical Distribution 7te District is confident that the surveillance tes -Juo of the Electrical Distribution System (EDS) for Cooper Nuclear Statien is adequate. This confidence is based on the number and scope of actions that have been taken. The following summarizes some of the more significant activities and improvements that have been made during the current outage.
a) compared the General Electric ECCS input assumptions against the Emergency Diesel Generator (EDG) load calculation; b) upgraded the 480-volt undervoltage design; c) reviewed the 4160-volt first and second level undervoltage logic and conducted additional testing via special procedures, temporary procedure changes, or new surveillance procedures; d) revised the EDG sequential loading test procedure and performed the revised test on both divisions to ensure appropriate load shedding; e) reviewed maintenance practices regarding installation and removal of l devices such as cable ties, jumpers and contact boots and initiated j procedure changes where necessary; f) reviewed operating procedures for proper operation of the Electrical Distribution System; g) reviewed the battery load study and compared it with battery load testing procedures; h) reviewed Design Criteria Documents (DCDs) for AC, DC, and EDGs at the component level, including support systems (e.g., Puel Oil Transfer, HVAC, etc., that support the EDGs) to ensure proper testing / functionality could be demonstrated; and, i) reviewed the above DCD listings for Licensing commitments and open items identify items of potential safety significance.
Future actions planned by the District are addressed in response to Items 5 (e)1 and 5 (e) 2.
With regard to preconditioning, CNS will neither test nor repair components, systems, or structures for the purpose of satisfying as-found acceptance criteria in surveillance tests. As-found testing will be performed prior to maintenance requiring adjustment of setpoints or Page 17 of 19
(
- NLS940001-i July 28, 1994 Attachment re-calibration per the surveillance program. For example, prior to d
performance of Technical Specification instrument surveillance calibrations and setpoint adjustments as-found data will be recorded.
Similarly, prior to performance of maintenance on essential electrical breakers, as-found data will be recorded.
- Inservice Insnection of Penetration Welds As discussed during the July 8, 1994, meeting with the NRC, examples of incorrect classification of primary containment penetration piping welds were identified. As a result, a commitment was made to assess the ISI Program, to submit an addendum to add the excluded welds, component supports, and pressure test boundaries to the ISI Program, and to submit '
relief requests if required prior to the 1995 refueling outage to ensure ASME Section XI requirements are implemented. Upon completion of these activities, the District will consider the ISI Program to be technically adequate and complete.
CAL 4-94-06b Item 5 (h) :
" Discuss the basis for your assurance that the testing programs for other licensed activities are adequately implemented. "
NPPD Response As discussed in Item 5(e), the surveillance testing for the major components of six critical plant systems has been reviewed to ensure conformance to the USAR and Technical Specification testing requirements.
These reviews were performed on systems with substantial safety significance: High Pressure Coolant Injection, Reactor Core Isolation Cooling, Residual Heat Removal Low Pressure Coolant Injection Mode, Core Spray, Automatic Depressurization, and Emergency Diesel Generator Systems.
The review found several discrepancies between CNS tests and the USAR. The discrepancies were corrected by USAR revisions or were incorporated into surveillance test procedures.
As a result of the investigation of the undervoltage trip assembly problems, the District also reviewed its program for logic system functional testing (LSFT). This review included the following systems:
High Pressure Coolant Injection Standby Gas Treatment ;
Reactor Core Isolation Cooling Reactor Building HVAC
]
Reactor Protection Diesel Generator HVAC {
Control Room HVAC Reactor Equipment Cooling Residual Heat Removal Core Spray Alternate Rod Insertion Fire Protection j Service Water Low-Low Set !
Automatic Depressurization Diesel Generator Lube Oil !
Standby Liquid Control Diesel Generator Auto Start Diesel Generator Fuel Oil Primary Containment Isolation (Gr 1-7)
Diesel Generator Starting Air Anticipated Transient w/o Scram Page 18 of 19
1
" 4 h NLS940001 July 28, 1994 Attachment 1
Each contact in the above listed systems was evaluated to determine if it performed an essential safety function and to determine whether a '
procedure existed which confirmed each contact's operability. Where i testing was not being performed, either appropriate procedures were revised or special test procedures were issued to perform the testing.
Completion of this testing has confirmed the design and functionality of the logic systems. From all of the testing performed, one minor, non-safety significant discrepancy associated with relay timing was noted.
Time delay relay REC-REL-1FR was found outside of its allowable range (27 to 33 seconds), but within procedural limits (15 to 60 seconds). Actual relay time delay was 33.27 seconds. The relay was calibrated and retested satisfactorily.
Furthermore, the District has implemented several orograms and activities to critically evaluate and improve CNS operation. M 3 art of these longer range programs, a series of self-evaluations of key grams continues to be performed, including those involving licensea westing activities.
Examples include: fire protection, MOV program, Appendix J, ISI, IST, and instrument setpoint. " Health Reports" are also being generated for each program. These reports consider a number of program performance factors including currency of the program with industry practice, currency with regulatory issues and commitments, and establishment of adequate program centrols. The health reports for activities involving testing programs include the surveillance testing program, the calibration program, inservice testing program, containment leak rate testing program, relief valve setpoints, instrument setpoints, relay setpoirts, and the MOV program.
While no significant deficiencies were identified, a health report for the Protective Relay Setpoint Program identified concerns related to overall program management. Previously, control of the setpoints included in this program was considered one of many elements of the electrical maintenance program, not a unique setpoint program. Currently, program responsibility has been assigned to the design engineering group.
In addition, inservice testing and inspection, containment leak rate testing (program upgrades in progress), and the Check Valve and vendor Manual Programs were all found to have health ratings that require further in-depth assessment and program improvements. The most significant concerns have been related to program ownership and support (i.e.,
management) , not technical concerns. No technical deficiencies that would impact safe plant operation have been identified. Management concerns previously noted will be addressed. Any safety significant technical deficiencies discovered during in-depth program reviews will be evaluated for impact on safe plant operation and aggressively resolved.
While some activities remain to be completed, the District has concluded that testing programs for other licensed activities are adequately implemented.
Page 19 of 19
e .
.d COOPER NUCLE AR STATION P.O. BOX 94, BROWNVILLE, NE8RASKA 68321 Nebraska Public Power District " T M ""
= = , _ _
NLS9400026 August 8, 1994 Mr. L. J. Callan Regional Administrator NRC Region IV 611 Ryan Plaza Drive Suite 400 Arlington, Texas 76011
Subject:
Response to Request for Additional Information Cooper Nuclear Station Docket No. 50-298, DPR-46
References:
- 1. Confirmatory Action Letter (Revision 2) dated July 1, 1994 to Guy R. Horn - Nebraska Public Power District (CAL 4-94-06B).
- 2. Letter from G. R. Horn (NPPD) to L. J. Callan (NRC) dated July 29, 1994, " Response to Confirmatory Action Letter."
- 3. Meeting Between Nebraska Public Power District and the Nuclear Regulatory Commission on July 29, 1994, concerning restart readiness.
l
- 4. Confirmatory Action Letter Dated August 2, 1994, to Guy R. Horn
- Nebraska Public Power District (CAL 4-94-08). )
Dear Mr. Callan:
On July 1, 1994, Confirmatory Action Letter 4-94-06B was issued which verified, among other things, that Nebraska Public Power District (the I District) would provide the Nuclear Regulatory Cournission (NRC) Regiorf IV )
of fice with a letter that discussed eight areas of interest. l On July 29, 1994, the District provided the letter to the NRC and participated in a meeting with the NRC to discuss plant restart. With these two activities l completed, all items in CAL 4-94-06B that were agreed upon as a precursor to I plant restart were satisfied. However, at this meeting, the NRC requested additional, more detailed information regarding the District's component and ,
system preconditioning policy, and its relationship to the implementation of l testing programs. The NRC also requested, prior to restart, that the District )
document some of the detailed discussions held during the meeting and, in some l cases, provide more detailed information on how reviews addressed in the July 29, 1994, letter were conducted. Attachment I to this letter provides the detailed information.
On August 2, 1994, the NRC issued CAL 4-9/.-08, which requested that (as a supplement to the CAL 4-94-06B response) the District describe its basis for l ccg hat an adequate review of Cooper Station operational experience,
- w w rsooso-94oeO -
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NLS940026 August 8, 1994 Page 2 industry experience, and NRC information has been conducted to support plant restart. The NRC requested that the District's discussion also address two recent cases where previous District reviews apparently did not address certain precursor information. Attachment 2 to this letter provides this information. The NRC requested that all of the above information be provided before plant restart and that the information be discussed at a public meeting, currently scheduled for August 12, 1994, at the Cooper Station.
All of the District's activities, collectively considered, represent an +
extensive amount of work aimed at confirming that there are no significant issues at the Cooper Station which would warrant continued plant shutdown.
The District has been very responsive to NRC concerns and often has conducted investigations that typically would not be considered a condition for plant restart. The District acknowledges that some of its reviews (e.g. , Operating Experience Reviews) may not have identified all issues. Although some investigations are ongoing, the District does not anticipate that its continuing efforts will uncover deficiencies that have a significant impact on public health and safety. If any safety significant findings occur, the District will take appropriate actions up to and including plant shutdown, if necessary, of course, further evaluations will be conducted as soon as possible, consistent with schedules discussed with the NRC. -
If there are any questions regarding information presented in the attachments, or on other matters, please call.
Sine rely t.
V ce resident, Nuclear RCG/nr
- l Attachments !
1 l
cc: U.S. Nuclear Regulatory Commission w/ attachments Attention: Document Control Desk NRC Resident Inspector Office w/ attachments Cooper Nuclear Station NPG Distribution w/ attachments
. .a . , - _ ~ - - - . - - - - . -- .-- . - - . - . - - .-
NLS940026 1 August 8, 1994 ATTACHMENT 1 A.. DETAILED DISCUSSION OF INITIATIVES '
Recent events at Cooper Nuclear Station (CNS) prompted several District initiatives to determine the scope of the equipment and process deficiencies that exist at the Cooper Station. Many of the actions taken to correct immediate deficiencies have been detailed in meetings and/or other correspondence with the NRC. While there may be several ways to perform reviews of issues, the District is confident that its approach is satisfactory for determining restart readiness. The following section details actions taken by the District.
j l
- 1. CONFIGURATION CONTROL - CABLE TIE l 1
The District concludes that the following actions represent a comprehensive I investigation of the cable tie issue and should prevent recurrence of similar deficiencies. The District took the following actions to determine the scope of the problem and to correct any actual or incipient configuration control '
deficiencies.
l l
First, a walkdown was conducted to verify that no similar cable tie installations were in place. None were found. The next step was to review station mechanical and electrical maintenance procedures; surveillance l procedures in the chemistry, operations, and instrument and control areas; and '
the 14.x series instrument and control procedures, to ensure that configuration control had been maintained. Three mechanical procedures and fifteen electrical procedures required revision, along with three minor discrepancies in the operations and instrument and control procedures. No discrepancies were identified in the chemistry procedures. The above listed items will be corrected prior to next use of the procedure and do not adversely impact restart of the plant.
l Concurrent with these activities, field walkdowns were performed to look for I deficiencies that could have been created as a result of using the deficient procedures. No equipment configuration discrepancies were found. Based on these activities it was reasonably concluded that the cable tie condition was limited to the example identified.
~
To ensure that configuration control continues to be procedurally maintained, a revision has been made to Maintenance Work Practice (MWP) . 5. 0. 4 to add guidance to further ensure that any impairments, changes, or blocking devices installed during performance of maintenance are removed prior to completion of the procedure. Also, management has held meetings with maintenance personnel to emphasize expectations with regard to configuration control, procedure compliance, and immediate correction of ambiguous or incomplete procedures.
Additional meetings will be held to ensure that sensitivity to this issue continues.
Page 1 of 9
l NLS940026-August 8, 1994 ATTACHMENT.1
- 2. LOGIC SYSTEM FUNCTIONAL TESTING j The activities summarized below provide adequate assurance that logic system )
functional testing at Cooper Station is adequate. This concern evolved as a l
result of the discovery of the RER Service Water Booster pump contacts that '
had not been tested. The process utilized for this issue is described below )
)
When the District discovered that contacts had not been tested as required, a review of the following systems was begun:
I High Pressure Coolant Injection Standby Gas Treatment Reactor Core Isolation Cooling Reactor Building HVAC Reactor Protection Diesel Generator HVAC Control Room HVAC Reactor Equipment Cooling Residual Heat Removal Core Spray Alternate Rod Insertion Fire Protection Service Water Low-Low Set Automatic Depressurization Diesel Generator Lube Oil Standby Liquid Control Diesel Generator Auto Start Diesel Generator Fuel Oil Primary Containment Isolation (Gr 1-7)
Diesel Generator Starting Air Anticipated Transient w/o Scram t The elementary logic diagrams for each system were reviewed, contact by contact, I and correlated against the existing surveillances. The screening methodology was
- as follows: ;
- a. Does an existing surveillance actually verify the operation of the
- contact directly? If yes, then no further action is necessary. If no, then proceed to b.
- b. Does the contact perform an automatic essential function as determined by an engineering review of the Technical Specifications and the USAR? If yes, then test prior to startup. If no, test after startup.
This review was completed on June 5, 1994, and testing commenced. In mid-July, ,
due to a question concerning the LOCA signal auto close contacts for the Core Spray full flow test valves (which had been scheduled for post startup testing),
a re-review of the post startup population of contacts was directed by senior ,
management using this additional criterion: i Is the contact operationally significant (i.e. , interlock that prevents an operator error) and not verified by existing testing? If yes, then test ,
before startup. If no, then test after startup.
The second screen was completed on July 18, 1994. All contacts have been satisfactorily tested. A plan will be generated to address contacts requiring testing after startup.
i Page 2 of 9
g a NLS940026 August 8, 1994 ATTAcrumpi 1
- 3. SURVEILLANCE REVIEW The District concludes that the following activities adequately determined the extent of the surveillance deficiency revealed by the undervoltage and load shed testing inadequacies. A team of experienced Senior Licensed Operators reviewed the CNS Technical Specifications, USAR, and surveillance programs to identify any weaknesses or discrepancies. The major components (i.e., pumps and valves) of the following systems were reviewed: High Pressure Coolant Injection, Reactor Core Isolation Cooling, Residual Heat Removal (Low Pressure Coolant Injection mode), Core Spray, Automatic Depressurization, and Emergency Diesel Generators.
The review was performed as follows:
e An existing cross reference between Technical Specifications and surveillance procedures, which is maintained by the Surveillance Coordinator, was independently reviewed for correctness.
- The Technical Specification surveillance requirements were reviewed against the respective surveillance procedures to determine if the requirements were being met, e USAR sections describing the six systems were reviewed to determine if the USAR requirements were being met by the surveillance.
The above reviews represent a significant undertaking by District personnel in a short period of time (July 2 to July 5, 1994). Reviewers developed a list of ;
questions / discrepancies which was assigned to the appropriate departments j (engineering, maintenance, etc.) for resolution. The discrepancies have been ;
evaluated and incorporated into surveillance procedures, or corrected by USAR revisions. Additionally, the Design Basis Reconstitution Project will be accelerated and will include a review of surveillance testing adequacy for all systems in the project._
Based on the above reviews, the District has reasonable assurance that surveillance procedures adequately 1uplement regulatory requirements.
- 4. DESIGN BASIS REVIEW OF THE ELECTRICAL DISTRIBUTION SYSTEM While the reviews of various specific items were addressing individual concerns, the District determined that a comprehensive evaluation of the entire syr' tem should be performed to ensure that the problems were not endemic. As a secondary matter, this review also would address the adequacy of implementation of the j Operating Experience Review (OER) program. This effort has received additional ;
scrutiny because of its failure to adequately address the Westinghouse DB 50 i breaker issue. The Electrical Distribution System (EDS) (AC Distribution, DC )
Distribution, and the Emergency Diesel Generators) was chosen because many of the recent problems appeared to affect electrical components and testing, and because of this system's critical nature. The investigation concluded that EDS components would have perforToed their intended safety function.
Page 3 of 9
, , NLS940026 August 8, 1994 ATTACHMENT 1 Starting on July 19, 1994, a multi-discipline integrated review of the EDS was performed. The team consisted of personnel from the Engineering Department and Senior Reactor Operators. This review utilized design criteria documents (DCD) and evaluated the actual requirements at not only the systems level, but also at the component level. Included in these system level and component level reviews were support systems such as DG fuel oil, HVAC, DG lube oil, etc. Each of the commitments af fecting testing or plant safety was reviewed to determine if they were adequately met. The initial review of the DCDs resulted in 49 questions requiring further evaluation and were investigated by Design Engineering, System Engineering, Operations Engineering, Configuration Management, or Operations Support Group. All of these items have been addressed. The review was completed on July 28, 1994.
B. ADDI'"IONAL DISTRICT REVIEWS While the actions taken as a result of the technical issues that arose during the current shutdown provide some assurance t.nat systems and components required for plant operation will function as required, the District concluded that additional reviews were warranted before startup. Therefore, the following actions have been taken:
- 1. OPERATING EXPERIENCE REVIEW In 1993, the District recognized that its Operating Experience Review (OER)
Program must be improved. This effort began in September 1993. The 1993 program began with a review by the Corrective Action Program Overview Group (CAPOG) of twenty percent of approximately two years of operating experience documents. On December 1, 1993, due to approximately a ten percent rejection of OER assessments, the sample size was expanded by another twenty percent. As discussed further in Attachment 3, the SBM switch and REC corrosion-related correspondence were not in the CAPOG sample population. Again, CAPOG re-reviews were a sampling effort that was not intended to assess all OER closeout documentation. Therefore, the fact that these issues were not satisf*actorily closed was not fostered by 1993 OER oversight efforts.
However, due to the failure of the 480 VAC undervoltage trip devices, the District has commenced an additional pre-startup review of closed OER information. The scope of this review covers all closed OER responses for the years 1992, 1993, and 1994, all closed pre-1987, and 25% of 1987-1991 responses.
The 1992-1994 period was chosen to validate the adequacy of the current program and represents approximately 25% of the entire historical database. A 100%
review of the pre-1987 period was chosen because there was an apparent lack of formality in the program at that time. A 25% sample of the 1987-1991 population was chosen to provide assurance of program adequacy after it was formalized in 1987. This recent limited review provides a reasonable basis for the District's Page 4 of 9
l 1
- ,. ,, NLS940026 1 August,8, 1994 ATTACHMENT 1 l
conclusion that the OER program has not overlooked issues that have a significant l impact on plant safety. The screening criteria used during this review are as follows:
e The item could adversely affect nuclear safety.
- The item is needed to comply with the CNS Technical-Specifications.
- The consequences of not completing the OER action could affect the ability of a safety system to satisfy its design function.
- The consequences of not completing the OER action could result in reduced safety system availability.
The closure documentation for items meeting the screening criteria are then reviewed for adequacy. If the basis for closure does not appear fully adequate, the item will be re-reviewed by NPPD engineering. CNS management will determine if pre-startup actions are required for any inadequate responses as determined by engineering. If an item does not satisfy the above criteria, it is assumed that the previous review, if inadequate, would not have a significant safety impact. .
Approximately 14% of the pre-1997 itsms, approximately 6% of the 1987 - 1991 items, and approximately 0.4% of the post 1991 items (2 out of 552) have been returned for review of response adequaiy.
A full review of the OER database responses for adequacy will be performed with an estimated completion time of 2 years.
The LER database also is being screened to identify recurring issues. Recurrence of the same or similar issues is indicative of a potentially inadequate corrective action. Those items found by the screening will be evaluated against the criteria defined above to determine if corrective action review is required prior to startup and CNS management will determine if any followup corrective 4 actions will be required prior to startup. The remaining items will be reviewed after startup and the need for further action determined.
- 2. ASSESSMENT OF COMMUNICATION EFFECTIVENESS Recent events at CNS have shown that additional efforts are necessary to ensure that everyone understands management expectations, especially for those issues that have been named as causes of recently discovered deficiencies, e.g.,
procedure use, preconditioning, and importance of problem identification. Since the maintenance organization also has been involved in several recent findings, additional management meetings have been held with the maintenance staff to discuss issues and to communicate expectations.
To reenforce the expectations expressed in the management meetings, the Site Manager issued a memorandum to the site dated July 29, 1994. This memorandum specifically addressed preconditioning of components for the purpose of passing ,3, Page 5 of 9
NLS940026 August 8, 1994 ATTACHMENT 1 surveillance tests, maintaining a questioning attitude, and the importance of clear and precise communication.
Independent of the above, from July 30, 1994, to August 1, 1994, the QA Division conducted a series of interviews with maintenance, operations, instrumentation and control, and chemistry to assess the state of understanding and acceptance of management's expectations. A specific list of questions covering procedural adherence, preconditioning, and identification and reporting of deficiencies was used. The following discussion provides a summary of the QA effort.
Preconditioning The interviews had mixed results. For example, within the areas explored, management has been effective in communicating its expectations to NPG personnel with one notable exception. While over 93% (222 of 238) of personnel interviewed had an acceptable understanding of what constitutes preconditioning, 45% (107 of 238) did not clearly understand the importance of not preconditioning. The majority of these personnel discussed the effects on as-found readings, the ability to accu *;ately identify problems or the inability to trend problems.
While these are also important factors, the key issue of functionality does not appear to have been adequately communicated and/or absorbed. It appears that this ' tack of full understanding is the result of inadequate training on the subject.
CNS management is currently evaluating appropriate ways to expand preconditioning )
training to ensure complete understanding of the policy by all personnel. ,
l Procedure Adherence Interview results indicate that there is a very good understanding of management's expectations throughout the Nuclear Power Group. Virtually every individual interviewed clearly understood both the need for procedural use and compliance, as well as the need to question the adequacy of the procedures and instructions they use as part of their daily routine. Fifteen percent of interviewees, however, expressed that they did not fully understand management's expectations, many because the expectations were changing so rapidly, it was difficult to definitively state that they were understood. This is an understandable reaction to the many recent culture improvement initiatives.
Through continued management reenforcement of expectations, this concern will dissipate.
Problem Identification The interview results indicate that management has been very effective in communicating expectations in this area. Virtually all of those interviewed expressed a clear understanding of their responsibility to identify and document ,
problems and concerns to ensure that they are corrected. However, management is l concerned that interviews also indicated that several individuals are reluctant I and/or uncomfortable with escalating problems that they did not feel had been resolved to their satisfaction. In this regard, reluctance by one individual is too many. Therefore, management will be increasing its focus on this aspect of problem identification.
Page 6 of 9
'
- NLS940026 August 8, 1994 ATTACHMMEL1
- 3. STARTUP AND POWER ASCENSION MANAG m "T PLAN Cooper Nuclear Station has developed a Startup and Power Ascension Management Plan to ensure that plant equipment, personnel performance, and organizational responsiveness are ready to support a safe and reliable plant startup and ascension to full power operation. A copy of this plan is provided (for information) as Attachmer.t 3. The District does not anticipate forwarding subsequent revisions to the NRC. Tne Plan's purpose will be accomplished through
, the following objectives:
- Assign temporary positions and responsibilities to provide accountability and clear lines of responsibility during the startup and power ascension process.
a e Establish communication paths to ensure accurate and timely transfer of information to support startup and power ascension, e Describe outage activities to ensure completion of work supports a safe startup.
- Resolve emergent issues in a timely manner so safe startup and power
-ascension are not impeded.
- Conduct startup and surveillance testing in a safe and efficient manner to ensure that system and component operability support startup and power ascension Two aspects of the plan are of special interest. First, each system engineer will review open items for his or her system to ensure there are no unresolved items which may impact that system. Open items for review include (among others) operating experience reviews, maintenance work requests, and temporary conditions. The completion of this review will be certified by the system engineer and reviewed by management.
Second, the manager of each station department will review open action items, condition reports, training, etc., to ensure that his department is ready to support startup and plant operation. As with the system engineer, the completion of the review will be certified by the department manager and reviewed by senior management.
Any item that meets one or more of the following criteria must be addressed prior to startup:
- The item could affect nuclear safety.
- The item is necessary for a safety system to satisfy its design function.
- The item is needed to comply with the CNS Technical Specifications.
- The item may result in reduced safety system availability, increased l forced outage rate, or reduced capacity factor in the time before it is completed or resolved.
l Page 7 of 9 l
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,~ , NLS940026 August 8, 1994 ATTACHNENT 1
- 4. FIELD COACHING TEAM obtaining prompt and precise feedback on performance in the field has been a 4 problem at Cooper Station. This has occurred in great part because effective i s communication methods to ensure that this information exchange occurred did not ,
exist in all areas. To remedy this deficiency for the short term, CNS has established a multi-diaciplined team of CNS personnel headed by an independent ,
manager charged with monitoring operations, maintenance, and surveillance testing in the field to ensure management requirements for proper testing and maintenance are understood and executed.
F Charter A charter has been written for this Field Coaching Team (FCT) which establishes specific criteria for observation and evaluation of field activities. At a minimum, the FCT team will observe adherence to procedures, identification and ;
resolution of procedural inadequacies, awareness of any potential for a process or activity to contribute to preconditioning, demonstration of effective communication, and the performance of work in a safe and quality manner. (
Scope r
I This process will focus at a minimum on:
e Adherence to procedures / instructions. !
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- Identification and resolution of procedure / instruction problems and 1
- inadequacies.
k e Identification and resolution of any potential preconditioning problem. ]
e Identification and resolution of ineffective communication. 1 a
J e Ensuring effective utilization of resources to accomplish tasks safely and j with quality results.
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e Insuring any perceived schedule pressure is corrected. I 1'
) e Insuring identification of problems and generation of CRs when l appropriate.
i e Application and consistent use of self-checking.
- Supervisory involvement in field activities.
.EESLERDA FCT personnel will be provided with orientation training by the Site Manager to ensure'that they fully understand management expectations. Once trained, team i members will disperse into the field, making their presence and function known l to all personnel engaged in an observed activity. At no time will the team . ,3, 1
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a NLS940026 August 8, 1994 ATTACIDENT 1 subvert the role of line management -- in fact, they will serve as augmentation to line management's ability to observe and correct inappropriate practices.
Specific techniques for assessment will be as dictated by the activity being observed, with appropriate consideration to the level of intrusiveness necessary to fulfill the objective and purpose of the FCT process. The District currently anticipates that the FCT team will observe pre-startup testing, and startup and t power ascension testing. Once the startup and power ascension is complete, the team will remain.in place to observe field activities until its purpose has been fulfilled.
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, a NLS940026 August 8, 1994 ATTACHMENT 2 SBM Switches and Reactor Ecuipment Coolina Pipinc As noted in Attachment 1, the 1993 OER review effort established a screening criteria for determining which findings required additional focus. This effort utilized a sampling approach to determine with reasonable assurance that previous OER efforts were satisfactory. Results of an assessment of the 1993 reviews could f all in one of three primary categories: (1) the components were not part of the sample group and therefore, the District's re-review did not directly miss potential safety issues, (2) the components were reviewed by the District as part of its sampling effort and it was reasonably concluded that the issues had been adequately addressed, or (3) the components were reviewed by the District as part of its sampling effort and it was erroneously concluded that the issues had been adequately addressed.
A review was performed to determine whether the SBM switches and REC issues had been specifically assessed by the OER review. Neither the SBM switches nor the REC issues were included in the sampling review. Therefore, it is reasonable to conclude, based on current findings, that these previous reviews were adequate.
This cor clusion, however, should not be considered an excuse for not identifying the SBM switch and REC issues. Proper questioning attitudes should have led to further discussion and satisf actory resolution of these issues. Notwithstanding these conclusicus, the District assessed the potential safety significance of SBM switch failures and the REC System. A brief summary of safety significance conclusions is provided below.
SBM Switches A review of SBM switch operating history at CNS illustrates that since GE SIL 155, "Possible Failures of Type SBM Control Switches," recommended inspection and refurbishment of the switches in 1980, there have been two switch failures (February 1989 and July 1994) due to the phenomenon described in the SIL. Seven additional switches with broken cam followers have been observed. However, this condition did not result in switch failure and none of the failures or cracks have occurred in switches refurbished in 1980. -
During recent inspections a majority of switches not refurbished in 1980, had one or more cam followers categorized as " Category B" per GE SIL 155. However, this status is not considered a failure. GE does not recommend these switches be replaced and has conducted testing that shows approximately 45,000 successful switch cycles can be expected before switch failure. Therefore, the Category B switches are expected to perform upon demand. However, the District will establish a replacement protocol for the pre-1976 switches.
With approximately 140 installed essential switches and 14 years of operating experience since switch refurbishment, two switch failures equals a failure rate of 0.001 f ailures per year or approximately one switch f ailure every eight years, Additionally, industry experience (as t.videnced by industry data base searches) indicates an extremely reliable switch operating history.
The District evaluated whether any safety functions would have been defeated had the switch failures occurred during a design basis accident. In summary, no safety functions would have been adversely impacted. This is due primarily to Page 1 of 2
NLS940026
. e August 8, 1994 M ACHMENT 2 a combination of design redundancy in the switch contacts and components that are not required to change position to perform their intended safety function.
REC System On July 29, 1994, a pinhole leak was discovered in a 12 inch non-essential REC weld. A section of the weld containing the flaw was sent to General Electric for metallurgical examination. The examination determined that Intergranular Stress Corrosion Cracking (IGSCC) was the most likely cause. The root cause was then determined to be nitrite induced cracking similar to that experienced in 1979 and 1980 at CNS. Subsequently, a second leak was found in a 6 inch section of non-essential piping.
An inspection program was initiated using the methodology defined in NCIG-02 (revision 2), " Visual Weld Acceptance Criteria, Volume 2: Sampling Plan for Visual Reinspection of Welds." The scope of the inspection eventually encompassed Ultrasonic Testing (UT) of 117 welds in the essential portions of the system piping, Of the 117 welds examined, 5 were found to have crack-like indications. Of the 5 welds with indications, 4 were acceptable per IWB-3600.
All 5 weldo will be repaired prior to startup. The remaining 112 welds had no crack indications.
The District also has performed a preliminary safety assessment of the as-found condition of the REC system. Of the 5 flaws found, 4 were acceptable per IWB-3600 and did not represent a threat to piping integrity. The remaining indication was within the critical flaw size and therefore, had it continued to propagate, would have leaked before the structural integrity decreased below acceptable limits. The non-essential portions of the piping perform no safety j function and are isolated on a design basis event.
l The only other safety related system in which nitrites are or were used is the Diesel Generator Jacket Water System. The use of nitrites as a corrosion inhibitor in diesel generator jacket cooling water is common industry practice.
Per the Cooper-Bessemer "Model KSV Emergency Diesel Generator Lubricating Oil and Jacket Water Analysis Guidelines," (Revision 1 dated 1993) , a nitrite based corrosion inhibitor program is recommended. Eight of nine current owners follow this recommendation. No leaks have occurred due to cracking in the Diesel Generator Jacket Water System at CNS and Cooper-Bessemer has no history of jacket water leakage as a result of nitrite use.
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' ATTACHMENT 3 -
I NLS940026 ?g . , , . , 7,c: , .1g + c _. , .; .
- August 8, 1994 ' YIP. . . . . . , , .N :: - _,,
COOPER NUCLEAR STATION
's STARTUP AND POWER
. ASCENSION PLAN l l
1 (SHUTDOWN 94-03) l
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, o COOPER NUCLEAR STATION STARTUP AND POWER ASCENSION PLAN Revision 1 APPROVED BY:
N '
i Plal ManagerU Date
, , )) [)'Vk w) --
['e'70 Site Manager Date i
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i STARTUP AND POWER ASCENSION PLAN I
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PREPARED BY: Jeff Boyd Ed Jackson Jodie Knapp Wayne McKinzey SUBMnTED:
h Senior hhnager Site Support Date 14 i
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TABLE OF CONTENTS
~ 1i11C Eagc 1.0 PURPOSE 4 2.0 SCOPE 4
3.0 REFERENCES
4 .
4.0 STARTUP ORGANIZATION 4 5.0 OUTAGE ACTIVITIES 8 6.0 STARTUP OVERVIEW 9 ATTACHMENT l'- STARTUP GF VIZATION CHART e ATTACHMENT 2 - STARTUP TEST FILE
- ATTACHMENT 3 - POWER ASCENSION SCHEDULE
- ATrt.::HMENT 4 - MAJOR WORK PERFORMED
- ATTACHMENT 5 - MODIFICATIONS
- ATTACHMENT 6 - SYSTEM READINESS REVIEW CHECK 1IST ATTACHMENT 7 - MANAGEMENT VERIFICATION FOR STARTUP ,
- NOTE: Final mision will be provided witida 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> preceding piant startup.
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- 1. PURPOSE The purpose of this document is to establish Management's expectations for ensuring the safe and controlled return to service of Cooper Nuclear Station from shutdown 9443 that commenced May 25,1994. This will be accomplished through the following oldectives:
- Assign temporary positions and responsibilities to provide accountability and lines of responsibility during the startup and power ascension.
- Establish communication paths to ensure accurate and timely transfer of information to support the startup and power ascension. ,
- Describe outage activities to ensure completion of work supports a safe startup.
- Resolve energent issues in a timely manner so safe startup and power ascension are not impeded.
- Conduct startup and surveillance testing in a safe and efficient manner to ensure that system and component operability support startup and power ascension.
- 2. SCOPE This plan addresses the activities performed to ensure that plant operation, material condition, personnel performance, organizational responsiveness, and the functioning of administrative and work control processes are fully ready for a safe and reliable startup. The development and approval of this plan are part of the criteria on which the evaluation for startup is based. This plan consists of the following mdor elements:
- Startup Organization
- Outage Activities
- Startup Orerview
- 3. REERENCES 3.1 C.O.P. 2.0.1.1, Conduct of Infrequently Performed Tests or Evolutions -
3.2 G.O.P. 2.1.1, Startup Procedure 3.3 G.O.P. 2.1.1.1, Plant Startup Review and Authorization 3.4 CNS Procedure 0.2, Station Organization and Responsibility 3.5 S.O.P. 2.2.28.1, Feedwater System Operation
- 4. STARTUP ORGANIZATION This section describes the additional staffing (Attachment 1), their responsibilities, and the lines of communication used during preparations for and the conduct of startup and power ascension. As-a minimum, the staffing shall be available from the time the Reactor Mode Switch is plamt in the
' Start & Hot Standby" position until the second Reactor Feed Pump is in service (Ref. 3 3). The staffing can be established prior to startup to develop the startup schedule and make startup preparations.
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- 4.1. MANAGEMENT OVERSIGHT The Managanent Representative is an experienced NPG Manager assigned on-shift to provide 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage throughout startup ar.d power mer===iam He is responsible for
- t an overall perspective of the startup process. Seuld any significant re-straints or potential schedule impacts be encountered, he shmE be informed. Additional responsibilities include but are not limited to:
- Ensuring plant personnel are aware of Managemeen expectations on the impor-tance of open, two-way communication.
e Fostering and supporting our questioning attitude by ensuring concerns expressed by plant personnel are acknowledged and addressed in a timely manner.
e Allocating personnel and resources as needed.
- Apprising the Plant Manager of all off-normal and emessing issues that may impact plant startup and power ascension.
1 e Overseeing implementation of this plan.
4.2 NORMAL STAFF AUGMENTATION 4.2.1 Operations Department 4.2.1.1 Operations Management Representative The Operations Management Representative is an emperienced individual fmm Operations line management assigned on-shift (Ref 3.2) to provide continuous _
operations management representation and presence during the startup and power ascension. His primary function is to ensure shot the exercise of command and control authority by the Shift Supervisor and Centrol Room Supervisor is not diluted by the increased level of activities inherent in the startup. His responsibilities include:
- Providing 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, continuous shiR coverage. *
- Coordinating emergent work activisies with the Outage Director.
- Representing the Operations Manager on-shift.
- Providing immediate on-scene commitation and evaluation of emergent conditions.
- Responding to issues identified by te Shift Supervisor, assigning actions, and ensuring that each issue is properly resolved by the assigned organizational units.
- Facilitating and coordinating emesamt support activities provid . .
ed by other organizational units.
- Attending the shift turnover meetings in the Control Room.
- Informing the Management Repnsentative of significant re-Revision 1 Page 5 of 11
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straints and potential schedule impacts.
4.2.1.2 Startup Test Coordinator This position, assigned by Plant Management, is manned on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> basis by an individual holding an SRO License or SRO Cedification. The Startup Test Coordinator assists the Shift Supervisor to ensure that post maintenance and system testing is completed to support systesu and component operability. These nsponsibilities include:
e Identifying post-maintenance / modification tests to be perfonned during the startup and power ascension evolution.
e Identifying additional testing of plant systems and components to I be performed to provide assurance that safety-related and non-safety related systems will support safe and reliable operations.
e Maintaining a Startup Test File (Attachment 2) as a subset of the Power Ascension Schedule (Attachment 3).
e Coordinating the performance of test file items with the power ascension schedule.
- Updating the Operations Managanent Representative with testing status. ;
e Infonning the Operations Management Representative of signifi-cant restraints and potential schedule impacts.
4.2.1.3 Operations Shift staffing for startup and power ascension is increased over normal levels.
Additional stamng includes a Senior Reactor Operator, a Licensed Operator, and a Station Operator. Their responsibilities (Ref 3.2) are as follows:
e The Senior Reactor Operator observes overall operation in the Control Room to alert the duty crew of potential problems. This Operator is to remain independent from the duty crew and manipulate controls only if absolutely necessary and at the direction of the duty crew.
e The Licensed Operator is dedicated to verifying control rod movements. This Operator is to remain independent from the duty crew and manipulate controls only if absolutely necessary and at the direction of the duty crew.
e The Station Operator assists the duty crew during times when work load prevents the duty crew from performing manipula- .
tions in a timely manner. When not needed to assist the duty .
crew, this Operator is to tour the plant being observant to poten-tial plant problems.
4.2.1.4 Instrumentation and Controls Department Revision 1 Page 6 of 11
- ,; a Department Penannel will be on shift to provide support for the following
- Pre-planned or required surveillance procedures.
- Emergent issues as deemed necessary by the Shift Supervisor.
4.2.2 Other Departments Chemnistry, Health Physics, Maintenance, and supped organization staft'ing is pmvided on shift during the startup and power ascension evolution. Maintenance support personnel are pre-selected and designated to respond to emergent work. The personnel, reposting through the Outage Organization are assigned to shift work and art available 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day in the event of emergent work.
4.2.2.1 Chemistry and Health Physics
- Health Physics will be available fnr 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage to ensure radiological coverage for emergent work and/or emerEency response.
- Chanistry will provide 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> support for increased number of reactor coolant chanistry samples and any other emergent work.
4.2.2.2 Maintenance Department Personnel will be on shift to provide support for the following:
- Pre-planned or required surveillance procedtires.
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- Emergent issues as deemed naceccary by the Shift Supervisor.
4.2.2.3 Support Units Other organizational units will be available (on-site or on-call as appropriate) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day to respond to emergent issues. These Support Units include per-sonnel from the following areas: {
- Nuclear Engineering Department
- Plant Engineering i
- Site Services
- Training 4.3 FIELD COACHING TEAM A Field Coaching Team (FCT) process will be employed for the purpose of independently assensing performance of startup and power ascension activities. These assessments are to ensure Management expectations are understood and complied with.
The organization includes an FCT Manager who is responsible for coordination of FCT .'
actividies and for communicating the results directly to the Site Manager. Personnel assigned will possess qualifications commensurate with the activities being assessed.
Fudonal areas taqgeted for assessment are Operations, Instrument and Control, ,, ,
l Maisdenance, Engineering, Chernistry, and Health Physics.
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' At a minimum, the Field Coaching Team will be focusing on the following areas:
e Identification and resolution of procedure and instruction inadequaaes.
e Idendfication and resolution of any potential preconditioning concerns.
e Identificadon and resolution of ineffective ca==unication .
e Insuring effective us of resources to accomplish tasks safely with quality results.
e Insure any perceived schedule pressure is corncted. '
- Insuring Condition Reports are generated when appropriate.
4.4 COMMAND AND CONTROL This section clarifies command and control authority and lines of communicadon.
The duty Shift Supervisor is in charge of plant configuration and control at all times (Ref 3.4). The tanporary staffing established to augment the normal opensdag staff during the startup and power ascension is structured to support the command and control authority of the Shift Supervisor and Control Room Supervisor.
The Operations Managernent Representative supports forthcoming events and coordinates areiaan to nsolve emergent issues. He interfaces with the Management Representadve and is infonned of testing status by the Startup Test Coordinator. All departments inform him of potential schedule impacts. This assures an adequate flow ofinfonnation 4
between managerment and plant startup support personnel.
- 5. OUTAGE ACTIVITIES This section describes the more significant work which was performed during shutdown 94-03 to correct or improve plant configuration.
5.1 MAJOR WORK PERFORMED Attachment 4 lists the major work items perfonned during the shutdown and includes a brief description of each.
5.2 MAJOR PLANT MODIFICATIONS l
The documentation provided in this section addresses the improvements that support safe ,
and reliable plant operation. The modificatio.n are listed by Design Change number and i description on Attachment 5.
5.3 TRAINING Prior to startup the necessary training shall be accomplished as follows:
5.3.1 Modifications 5.3.1.1 DC94-01 Battery Rooms Exhaust Fans and Non-Essential Control Build- j ing HVAC Trip. This Design Change will be presented to operators in j Lesson OT11015-94-08 which contains the following objectives:
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- Identify the purpose of DC94-01. l
- Identify the insarlocks between the essential control building 'l '
HVAC system and the batten moes exhaust fans and contml building non-essential HVAC system.
- Identify the location of HV-REL-9A,9B, 8A, and 8B relay panel and tesGack points ECBHI.1,2, ECBHH-1 and 2.
- Identify the change to Procedures 2.3.2.9, 2.3.2.10, 2.3.2.18, i 2.4.6.6., and 2.238 due to DC94 201. ,
53.1.2 DC94-166,480V Breaker Shunt Trip 5.3.1.3 DC94-223, HPCI-PS-68A, B, & C .,
5.3.1.4 TDC94-224, CS-MO-5A & B Time Delay Relay ;
5.3.2 Procedures j
.i Lesson OTH015-94-10 will be presented to operations personnel informing them l of recent Primary Containment Valve Control additions to the following: ;
5.3.2.1 COP 2.0.1, Operations Department Policy l 5.3.2.2 COP 2.0.2, Operations Logs and Reports 5.3.2.3 AP 0.26, Surveillance Program i
5.3.3 Startup Training Provided for Operators Prior to assuming the watch, the Operations crews responsible for the startup will be trained in the simulator for the evolutions they will be performing during i startup. These m4or evolutions will consist of the following 1
5.3.3.1 Achieving criticality.
5.3.3.2 Placing Reactor Feed Panp in service.
5.3.3.3 Placing Reactor Mode Switch to Run.
5.3.3.4 Synchronizing generator to grid.
- 6. STARTUP OVERVIEW This section describes the approval required for startup, the power ascension schedule, and addresses emergent issues.
6.1 STARTUP VERIFICATION Startup Verification is written conformation that the plant systems and individual Departments are ready to support safe startup and operation.
6.1.1 System Readiness Review Cheddist (Attachment 6)
This checklist provides documentation of reviews on each system by System Engineers to ensure readiness for plant startup.
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6.1.2 Management Verification for Stadup (Attachment 7)
Department Managers verify readmess for plant stadup.
6.2 STARTUP AUTHORIZATION Department Managers and Supervisors are responsible for performing a plant startup review, thus ensuring all applicable open items are addressed prior to reactor stadup.
SORC is responsible for authorizing the plant stadup upon satisfactory completion of the startup review. The following shall be reviewed and resolved by Management prior to stadup authorization being granted (Ref. 3.3):
- Operations Manager or Operations Supervisor shall review:
Equipment Clearance and Release Ordens, Valve Seal Log, Special Orders, Plant Temporary Modifications Control, and Surveillance Procedures.
- Engineering Manager, Operations Engineering Supervisor, or Plant Engineering Supervisor shall review:
Design and Equipment Specification Changes, Special Test Proce-dure /Special Procedures, Temporary Design Changes, and Reactor Post-Trip Review Procedure. .
e Maintenance Manager or Maintenance Supervisor shall review:
Work Item Tracking - Cornetive Maintenance, Work Item Tracking -
Preventative Maintenance, and Unscheduled Shutdown Item List.
- QA Manager shall review:
QA Commitments.
- Technical Staff Manager shall review:
Open Condition Reports requiring resolution prior to startup, Commit-ment and Open Item Tracking, Procedure Changes, Contact Licensing for Outstanding Commitments. ,
- SORC Chairman (Review and Authorization)
Review all items above and any exceptions which are forwarded to the Operations Manager for tracking and closure.
Once these items are reviewed, Attachments 6 & 7 are completed, and with Site Man-ager's concurrence plant startup will be authorized by the Plant Manager.
6.3 POWER ASCENSION SCIEDULE The Power Ascension Schedule (Attachment 3) is a schedule of the activities performed to progress from cold shutdown to full power operations. It is developed by the O & M Department and is based on procedural requirements for the startup. The Power Ascen-sion Schedule begins when approval to commence the startup process has been granted. -
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6A RESOLUTION OF EMERGENT ISSUES Emergent issues identified during startup need to be resolved effectively, with no degradation in plant configuration contal, work quality, or safety. Existing processes are used to identify and track issues and to manage follow-up activities. These processes are augmented by the Operations Managanent Repnsentative who evaluates new itens, -
initiates nodfications, and coordinates follow-up activities for priority items.
To ensure prompt management action, emergent issues and material discrepancies an reported in parallel to the Control Room and to the Operations Management Representa- i tive. Immediate response actions an initiated by the Contml Room and follow-up actions !
such as initiating planning and scheduling, alerting maintenance personnel, initiating call-ins, etc., are initiated and coordinated by the Operations Managanent Representative j with concurrence of the Management Representative. I l
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1 STARTUP AND POWER ASCENSION ORGANIZATION MANAGEMENT REPRESENTATIVE
........L................
D - JOBE i N . MACE RECOPSER ,
Ch OPERATIONS MANACEMENT STARTUP TEST d'
, REPRESENTATIVE COORDINATOR
- D- BLACK D- SHAW r N. STAIRS STARTUP COORDINATOR N- McKINZEY D- KOCH N WARD
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"N> ,
NED HP ENGINEERING REACTOR ENCINEER I6C MAINTENANCE MAINTENANCE WAREHOUSE CHEMISTRY O
" COORDINATOR COORDINATOR COORDINATOR ----.--.----.--- COORDINATOR PIANNING COORDINATOR C00RDINAIOR COORDINATOR
........... ........... -...--....- THOMPSON ----------- ----------- ----------- -----....-- .----.-.---
- D- WENZL D-CHARD / HALL D. LYMAN PETERSON D- HAIKENS D-CRAVIVRD D- PEBLEY D-WARNKE D- PIKE . .
N. CROTHEN N-OSHID/ N. STONER DEDIC N- SIAMA N-SCHMIEIAU N- CARSON N PARKHURST/ N- WARREN KIMBALL --
BALTENSPERCER be-s
) - DAY SHIFT
. - NICHT SHIFT r 40TE: 1) THE STARTUP AND POWER ASCENSION ORCANIZATION IS ESTABLISHED WHEN MODE SWITCH .
15 PIACED IN STARTUP AND SHALL REMAIN IN EFFECT UNTIL THE SECOND REACTOR FEED '
PUMP DISCHARGE VALVE IS IULLY OPEN.
- 2) COORDINATOR MEETINGS ARE CONDUCTED BY THE SENIOR MANAGEMENT REPRESENTATIVE AT 0630 AND 1830.
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STARTUP PLAN ATTACHMENT 2* - -
REVISION 1 MWRs BY SYSTEM As of Aug 1, 1994 STARTUP TEST FILE CIC WI NUM TEST REQUIRED WORK PERFORMED A0G-A0V-931AV 94-3283 SOAP TEST REBUILT OPERATOR 94-3283 STROKE VALVE REBUILT OPERATOR A0G-HX-1B 94-3583 VERIFY NO LEAK COVER GASKET LEAK AOG-RV-11RV 92-2760 VERIFY LEAKAGE REMOVED FOR TEST A0G-RV-15RV 92-2843 VERIFY LEAKAGE REMOVED FOR TEST A0G-SOV-SPV11B 94-3807 SOAP TEST REBUILT SOV 94-3807 VERIFY OPERATION REBUILT SOV I 1
A0G-TP-T2B 94-1425 VERIFY OPERATION REBUILD I 94-1425 VERIFY LEKAGE REBUILD l A0G-V-330 94-1466 VERIFY LEKAGE AND REPACKED VALVE OPERABILITY AOG-V-331 94-1449 VERIFY LEKAGE AND REEACKED VALVE OPERABILITY l
AR-MOV-161MV 93-2936 VERIFY LEAKAGE REBUILT VALVE 1
AS-AO-PCV810 94-1794 VERIFY LEAKAGE REPACKED 94-1392 VERIFY OPERATION REBUILT OPERATOR
' AS-CV-15CV 93-4589 VERIFYLEkAGE REBUILT VALVE
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ASB-B-1C 94-1436 VERIFY LEAKAGE OPEN FOR INSPECTION l 94-0685 MP 7.0.8.1 REPAIRED LEAK CD-AO-0CV54 94-2544 SOAP TEST AIR LINE REPLACE AIR LINE 94-2544 VERIFY OPERATION REPIACE AIR LINE CD-V-119 94-1926 VERIFY NO LEAK REPACKED VALVE.
CD-V-131 94-2421 MP 7.0.8.1 CUT PIPE AT VALVE CD-V-229 94-1927 VERIFY NO LEAK REPIACED VALVE CRD 94-0955 MP 7.0.8.1 WELDED IN LEAKING PIPE CRD-ACC-125(38-27) 94-1542 NPP 10.9 REPLACED CRD-ACC-125(46-27) 94-3591 NPP 10.9 REPIACED CRD-AO-CV126(34-31) 94-2619 NPP 10.9 ADJ CLOSE SWITCH 94-2416 NPP 10.9 ADJ VALVE OPERATION CRD AO-CV126(46-43) 94-2620 NPP 10.9 ADJ L!OSE SWITCH 94-0889 NPP 10.9 ADJ VAL 7E OPERATION !
CRD-AO-CV127(34-31) 94-2416 NPP 10.9 ADJ VALVE OPERATION I CRD-AO-CV127(46-43) 94-0889 NPP 10.9 ADJ VALVE OPERATION CRD-A0V-CV126(22-19) 94-2370 NPP 10.9 ADJ LIMIT SWITCH PAGE 1 OF 5
}
STARTUP PLAN ATTACHMENT 2 REVISION 1 MWRs BY SYSTEM As of Aug 1, 1994 STARTUP TEST FILE CIC WI NUM TEST REQUIRED WORK PERFORMED CRD-A0V-CV126(26-15) 94-2376 NPP 10.9 ADJ LIMIT SWITCH r CRD-A0V-CV126(30-11) 94-2375 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV126(30-31) 94-2372 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV126(34-27) 94-2374 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV126(38 27) 94-2373 NPP 10.9 ADJ LIMIT SWITCH CRD A0V-CV126(46-43) 94-2371 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV127(14-11) 94-2379 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV127(14-23) 94-2378 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV127(22 39) 94-2377 NPP 10.9 ADJ LIMIT SWITCH CRD A0V-CV127(30-19) 94-2383 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV127(30-35) 94-2382 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV127(30-39) 94-2381 NPP 10.9 ADJ LIMIT SWITCH CRD-A0V-CV127(34-31) 94-2380 NPP 10.9 ADJ LIMIT SWITCH CRD-SOV S0117(30-07) 94-2349 NPP 10.9 REBUILT SOLENOID VALVED CRD-50V-S0117(38-27) 94-2350 NPP 10.9 REBUILD SOLENOID VALVED CRD-SOV-S0117(42-11) 94-2348 NPP 10.9 REBUILT CRD- SOV-S0117 (46 -43) 94-2347 NPP 10.9 REBUILT CRD-50V-50118(30-07) 94-2349 NPP 10.9 REBUILD SOLENOID VALVED CRD SON-50118(38-27) 94-2350 NPP 10.9 REBUILD SOLENOID VALVED CRD-S07-S0118(42-11) 94-2348 NPP 10.9 REBUILT CRD-50V-S0118(46-43) 94-2347 NPP 10.9 REBUILT CW-V-67 94-2343 MP 7.0.8.1 REPLACED VALVE CW-V-71 94-2343 MP 7.0.8.1 REPIACED VALVE EE-STR-250HPCI(M014) 94-1271 SP 6.3.3.1.1 INSPECT MOTOR ES-AO-NRV3 94-2351 SP 6.4.8.10.1 REP 1 ACED OPERATOR 94-2641 STROKE FOR LEAKS CYLINDER REBUILT OPERATOR ES-A0V-NRV3 94-2667 SP 6.4.8.10.1 REPIACED LIMIT SWITCH ES-A0V-NRV4 93-4545 VERIFY OPERATION PACKING ADJUSTMENT ES-A0V-NRVSTV3 94-3053 VERIFY OPERATION REBUILTS 94-3053 SOAP TEST AIR REBUILTS CONNECTIONS PAGE 2 OF 5
STARTUP PLAN ATTACHMENT 2 -
REVISION 1 MWRs BY SYSTEM As of Aug 1, 1994 STARTUP TEST FILE CIC WI NUM TEST REQUIRED WORK PERFORMED ES-MO-NRV4 93-4545 ADJUST PACKING PACKING ADJUSTMENT ES-SOV-NRVSTV12 94-3109 VERIFY OPERATION REPAIR AIR LEAK ES-SOV-NRVSTV2 94-3165 VERIFY PP.0PER REPLACED FOR LEAKING AIR OPERATICN AND BUZZING TOO IDUD 94- N 5 SOAP T2ST VERIFY NO REPLACED FOR LEAKING AIR LEAYS AND BUZZING TOO 14UD HPCI SP 6.3.3.1.1 HPCI-V-44 94-3413 SP 6.3.3.1.1 REPAIR LO-F-BK01 94-3498 VERIFY D/P REPIACED FILTER I4GT-PI-205 94-3009 VERIFY PROP OPERATION REPIA(.E GAUGE MC-CR-1 93-4564 VERIFY PROPER OPERATION MC-CV-16CV 94-2060 VERIFY NO LEAKS HINGE PIN COVER LEAK MN APRM SP 6.1.3 MS-A0V-DRV8 94-1807 SP 6.4.8.2.8 REBUILT MS-A0V-PCV62 94-1096 STROKE FOR LEAKS REPACKED MS-AOV-VARIOUS 93-3415 SP 6.4.8.10.1 REPAIR MS-FE-122A 94-3060 ISLT SWITCH SENSE LINE MS-FE-127A&B 94-2500 VERIFY LEAKAGE CLEANED AND INSPECTED, ADDED CAGES MS-FE-SEVERAL 94-2499 VERIFY LEAKAGE CLEANED AND INSPECTED, ADDED CAGES MS-PR-SEVERAL 93-3192 VERIFY ANN OPERATION CAL CHECKS MS-SOV-SPV1331 94-2326) SOAP TEST FITTINGS REBUILT SOLENOID 94-2326 VERIFY OPERATION REBUILT SOLENOID MS-TP-1 94-2404 MP 7.0.8.1 REPIACED TRAP 94-2404 SP 6.4.8.9 REPLACED TRAP MS-TP-13 94-2404 SP 6.4.8.9 REPIACED TRAP j 94-2404 MP 7.0.8.1 REPIACED TPAP ;
MS-TP-16 94-2131 VERIFY OPERATION REPLACED TRAP l
MS-TP-SEVERAL 93-3277 SP 6.4.8.9 REPLACED TRAP l MS-V-27 94-2102 MP 7.0.8.1' REPIACED VALVE MS-V-663 94-1581 VERIFY LEAKAGE AND REPLACED VALVE OPERATION PAGE 3 OF 5
STARTUP PLAN ATTACHMENT 2- .
~
REVISION 1 MWRs BY SYSTEM As of Aug 1, 1994 STARTUP TEST FILE CIC WI NUM TEST REQUIRED WORK FERFORMED MS-V-766 94-1598 MP 7.0.8.1 ADJ PACKING MS-V-771 94-2386 MP 7.0.8.1 REPLACED VALVE MS-V-872 94-1316 MP 7.0.8.1 REPIACED VALVE MSIV SP 6.3.9.4 NBI-SOV-SSV739 94-3490 MP 7.0.8.1 REPAIR 94-3490 MP 7.0.8.1 REPAIR NBI-V-632 94-0163 ISLT REPIACED VALVES NM NBI 10.2 NMT-NDC-(131-4c) 94-2315 PERFORM OD-1 REPIACED REIAY OC-V-12 94-1582 VERIFY OPERATION REBUILT l 94-1582 SOAP TEST REBUILT '
OG-V-13 94-1582 SOAP TEST REBUILT 94-1582 VERIFY OPERATION REBUILT PC-TE-500D 94-2700 VERIFY OPERATION TROUBLE SHOOTING PMIS 94-3475 VERIFY PROP OPER REPAIR PTS RCIC SP 6.3.6.1.1 RCIC-CV-26CV 94-2290 MP 7.0.8.1 6.3.10.26 RCIC-PS-3070 94-1645 ISLT REPIACE TUBING RCIC-SW-S1 (MO-15) 94-4022 SP 6.3.10.24 REPLACED SWITCH 94-4022 SP 6.3.6.2 REPLACED SWITCH !
RCIC-SW-S2 (MO-16) 94-3958 SP 6.3.10.24 REPIACED SWITC !
94-3958 SP 6.3.6.2 REPIACED SWITCH l RF-A0V-FCV11BB 94-2468 ISLT ADJUST PACKING 93-3275 VERIFY OPS ADJUST PACKING 93-3275 ISLT ADJUST PACKING RF-SOV-TBTB 94-3070 VERIFY LEAKAGE REINSTALL RMP-RE-130B 94-2931 SP 6.3.7.2.3 REPLACE DETECTOR RPIS (30-03) 94-3911 VERIFY OPERATION OF REBUILT CONNECTION RED (FULL OUT) LIGHT ]
RPS/TG SP 6.1.9 )
RRV-155 93-4013 VERIFY PROPER PACKING
RESPONSE
j RR-V-156 93-4013 VERIFY PROPER PACKING
RESPONSE
j PAGE 4 OF S
7
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STARTUP PLAN ATTACHMENT 2 * . .
REVISION 1 MWRs BY SYSTEM As of Aug 1, 1994 STARTUP TEST FILE CIC WI NUM TEST REQUIRED WORK PERFORMED P.R-V- 18 6 93-4014 VERIFY PROPER PACKING
RESPONSE
RRIA-TI- 1A 94-2223 VERIFY PROPER TEMP INDICATION INDICATION RRMG-EXC-MGA 94-2508 VERIFY OPERATION REPIACED BRUSHES RRMG-REL-K35A 94-2637 VERIFY LIMITER CAL REIAY OPERATION RRMG-REL-K35B 94-2638 VERIFY LIMITER CAL REIAY OPEPATION RW-P-FDSP 94-2476 VERIFY LEAKAGE REPIACED AND REPACKED RWCU 94-3744 MP 7.0.8.1 RE TORQUED FIA' IGE BOLTS RWCU-A0V-FCV55 93-3996 ISLT REPAIR RWCU-FE-102A 94-2964 MP 7.0.8.1 CLEANED AiTD INSPECT RWCU SOV-SPV109A 94-3289 VERIFY OPERATION REBUILT SOV SW-V-55 93-2223 VERIFY NO LEAK REPLACED VALVE THROUGH TG SP 6.1.7 TG-TU-VAC LINES 93-4003 VERIFY VAC INDICATION CLEANED LINES TGl-R-101 94-2604 SP 6.4.8.2.7 CAL VIB INST PAGE 5 OF 5
e DAYS '
1 I 2 1 3 1 4 i S
MODE SWITCH TO STARTUP, 50P 21 1
+
HEATUP TO RATED PRESSURE (505 BPV1 eM PERFORM 500: DR GELL INSPECTION M
PERFORM N0ZZLE SURVE)S (DW1 M e INERTING THE DRYWELL di MODE SWITCH TO RUN ro
+ $
SP 6 3 1 I D/W PERSONNEL AIRLOCK DOORS S8: TEST x H
SYNCHRONIZE TURBINE GENERATOR, 50P 2.I.I k
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SP 6.3 3 1.1 HPCI IST & QTRLY TEST MODE SURV a y$
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x-v SP 14 6
/M .11 DRAGON INSTR VLV GUIDE t SECT 8. 31 o
&SP 6 3 6.1.1 RCIC IST & QTRLY TEST MODE SURV 3 M
SP 618 TURB CONTROL VLV FAST CLOSURE C/F a w POWER ASCENSION TO 1005
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8SP 10.2 IRM POWER CALIBRATION t25% POWER 1 SP 10.9 ROD SCRAM TINING - 17 RODS D .
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"~ COOPER NUCLEAR STATION '
$ jlU !!n5ln "e E U S $ ~ ' ~ ~ " " ~ ' #"* " " * " "" " '" ',
FORCED SHU100WN - DUE TO DG S INOP i e i o,..n. . syc. , im POWER ASCENSION SCHEDULE ,
STARTUP PLAN ATTACHMENT 4 -
REVISION 1 4
ACTIVITY IDENTIFICATION ACTIVITY DESCRDTION 942370 through 942383 CRD-AOV-CV126 & 127 Align Limit Actuators 942387 through 942397 (25 total) 943396 STP-94-100-1 CS B Flow Transient troubleshooting 942646 DG-RV-15RV Replacement 942520 EE-SWGR-480F As-build wiring 942521 EE SWGR-480G As-build wiring 943055 EE-MCC-Q(10B) CS-MO-26A Ground-replace trans-former SP 94-208 Perform UV Relay Testing 942486 T. Bldg. Exh & Supply fans DP < .25 941768 Replace Air Side Seal Oil Pump 942548 ID-P-AS Replace mechanical seal l 941495 MS-HO-GV1 Replace cylinder i 942410 MS-HO-SV2 Replace cylinder 942411 MS-HO-GV2 Replace cylinder 942412 MS-HO-GV4 Replace cylinder !
941932 NM-NAM-AR3 Wire harness binding 941933 NM-NAM-AR7 Wire harness binding ,
941934 NM-NAM-AR1 Wire harness binding 942537 NMI-NE-33E, NT-34E IRM E Spiking 942315 TIP Machine 3 K3 Relay replacement 943349 REC-P-C Inboard bearing failed-Repair / replace pump 942362 RF-CV-15CV Repair hinge pin cover gasket leak 943319-02 RHR-MO-39B LLRT repair 942510 RIIR-MO-16B Examine internals-LMS Compartment 942508 RRMG A & B Exciter & Generator brushes 942408 TGC-CPU-DEIIO1 BPV#1 Repair / replace ser-vo/LVDT 942568 NMI-NAM-41D IRM D Spiking j i
- ' - ~ ' ^
l STARTUP PLAN ATTACIIMENT 5 arvisioN1 l l
DESIGN CHANGE DESCRIPTION STATUS REPORT DATE l DC 94-209 Personnel Airlock Test 6-04-94 l connections DC 94-212 Penetration X-218 6-16-94 Modification DC 94-212A Penetration X-209 6-24-94 Modification DC 9&212B Penetration X-43 & X-44 7-08-94 Testable Flanges DC 94-212C REC LLRT Test 7-11-94 Connections DC 94-212D IA & SA X-21 & X-22 7-12-94 Isolation valves and Test Connection DC 94-212D-1 Install 2" Soft Seat CVs 7-12-94 for 65CV & 78CV
- DC 94-212E Instrument Valves and 7-09-94 Caps DC 96212F Instrument Lines Into 7-18-94 Containment DC 94-212II PASS System X-51F 7-08-94 DC 94-212J Piping Penetrations 2N 7-13-94 Upgrade DC 94-212M TIP CV Removal 7-22-94 DC 94214 Emergency Diesel Cabinet 7-01-94 Qualification DC 94-166 480V Bkr Shunt Trip 7-0494 DC 94222 PC-PT-2104A & B, PC- 7-10-94 DI"I'-20 Replacement DC 94223 IIPCI-PS-68A, B, C, & D 7-19-94 TDC 94224 CS-MO-5A & B TDR 7-26-94
STARTUP PLAN ATTACHMENT 6 -
Revision 1 SYSTEM READINESS REVIEW CHECKLIST SYSTEM NAME SYSTEM ENGINEER REVIEW
SUMMARY
(The System Enzineer shall initial each item below to confirm reviews are complete)
Sys tem open Maintenance Work Requests Plant Temporary Modifications Preventative Maintenance ACT items System Walkdown performed Nuclear Action Item Tracking REMARKS (The System Enzineer can provide any additional relevant information deemed necessary to provide a coanlete summary of system readiness)
System Engineer Signature Date ENGINEERING MANAGEMENT REVIEW & APPROVALS Supervisor Signature Date Engineering Mgr Signature Date COMMENTS:
- l l
SORC APPROVAL l
l SORC Chairman Date l
i SITE MANAGER APPROVAL
- l l
Site Manager Date .' l
- Required if comments noted l
, .c ,
STARTUP PLAN ATTACHMENT 6 -
Revision 1 SYSTEM READINESS' REVIEW System Enzineer Responsibilities A. Responsible for screening open items and development of the System Readiness Review Checklist (SRRC) as designated in this Attachment.
B. Responsible for ensuring that all open items related to startup are identified.
C. Responsible for review of non-open item (non-tracked) based issues that could impact system readiness, such as pending plant modifications, unanswered Engineering Memoranda, work /PMs that were scheduled to be done during the October '94 Outage, etc.
D. Responsible for evaluating the integrated effects of work and/or engineering issues on the system and developing justifi-cations to include or reschedule open items based on nuclear safety and reliability.
E. A listing of all items reviewed shall be attached to the SRRC for documentation purposes.
F. Responsible for ensuring that no open items impact a le startup of the plant.
System Engineer Review Scone A. Prior to startup, the responsible System Engineer shall review open items on the system. Open items will be documented in, accordance with this procedure. In this review, the System Engineer must consider the following sources of relevant system information:
Open Maintenance Work Requests
+ Open ACT items Open PMs a
Open PTMs B. The System Engineer shall also perform a system walkdown for startup related issues and attach the results to the SRRC.
p f
o * STARTUP PLAN XITACHMENT 6 -
)
Revision 1 I
C. The following guidance shall be used by the System Engineer to assess an open_ item:
The item does not adversely affect nuclear safety; The item is not needed to comply with the Technical I
Specifications; The item will not affect the ability of any safety system to satisfy its design function; The item is not likely to result in reduced safety system availability, increased forced outage rate, or reduced capacity factor in the time before it is completed or resolved.
EXAMPLES OF OPEN ITEMS Maintenance Work Requests Backlogged Preventive Maintenance Work Requests Plant Temporary Modifications Open/Walkdown Inspection Findings ACT items NAIT items Unanswered Engineering Memoranda
- Open Operating Experience Items (NAIT)
Commitments (NAIT)
Preventive Maintenance Activities (PMs) 2 3 of 3
- A.
STARTUP PLAN ATTACHMENT 7 Revision 1 MANAGEMENT VERIFICATION FOR STARTUP DEPARTMENT DEPARTMENT MANAGER In addition to G.O.P. 2.1.1.1 requirements, the following items have been reviewed to ensure no open items will impact safety on plant startup:
Signature
- 1. All department open items reviewed including:
- Maintenance Work Requests e Condition Reports e Commitment /Open Item Tracking a Procedure Changes
- Training
- Open OER Documents
- 2. Any other items considered important to safety.
I verify readiness to Startup and have completed an extensive walkdown of plant systems. The plant is ready to return to power operation. Any comments are noted below:
COMMENTS:
- DEPARTMENT MANAGER DATE REVIEWED:
SENIOR MANAGER DATE
- SITE MANAGER DATE 4 7.,
- Required if comments noted