IR 05000322/1989001
| ML20235Y946 | |
| Person / Time | |
|---|---|
| Site: | Shoreham File:Long Island Lighting Company icon.png |
| Issue date: | 02/28/1989 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20235Y942 | List: |
| References | |
| 50-322-89-01, 50-322-89-1, IEIN-84-20, NUDOCS 8903140695 | |
| Download: ML20235Y946 (24) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-322/89-01 Docket No.
50-322 License No.
NPF-36 Licensee:
Long Island Lighting Company P. O. Box 618 Shoreham Nuclear Power Station Wading River, New York 11792 Facility Name: Shoreham Nuclear Power Station Inspection At: Shoreham, New York
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Dates:
January 4 - February 20, 1989 Reporting Inspector:
F. J. Crescenzo, Resident Inspector Inspectors:
F. J. Crescenzo, Resident Inspector W. J. Raymond, Senior Resident Inspector, Millstone P. Kaufman, Project Engineer, Region I J. Carasco, Reactor Engineer, Region I Approved by:
O< C. k &4, b n/2e/e9 E. C. McCabe, Chief, Reactor Projects Section IB Date Inspection Summary:
1/4/89 - 2/20/89 (Report 50-322/89-01)
Areas Inspected: Resident and Region based inspection of operations, maintenance, surveillance, committee activities and license conditions. Two hundred and twenty eight hours of direct inspection effort were expended.
Results: No violations were identified. Two issues pertaining to ASME programs and replacement of Agastat relays remain unresolved.
i 6903140695 890302 PDR ADOCK 05000322 Q
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TABLE OF CONTENTS
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_P_AG__E 1.0 Persons Contacted....................................................
I 2.0 Facility Activities (71707/62703/40500)..............................
2.1 Summary.........................................................
2.2 ASME Code Deficiencies..........................................
2.3 Agastat Relay Deficiencies......................................
3.0 Facility-Tours (71707)...............................
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4.0 Plant Operational Status Reviews (71707/93702).......................
4.1 RBSVS "A" Initiation............................................
5.0 N P F-3 6 Li c en s e C o nd i t i o n s............................................
5.1 License Condition 2.C.14........................................
5.2 License Condition 2.C.12, Attachment 3, Item H..................
6.0 Preliminary Operational Readiness Review (71707/40500/40700).........
7.0 Facility Inspection Tour by Director, NRR............................
8.0 Al l e g a t i o n s ( 9 2 7 2 0 )..................................................
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9.0 Observation of Maintenance Activities (62703)........................
10.0 Maintenance Program Implementation (62700)...........................
11.0 Surveillance Testing (61726).........................................
12.0 Committee Activities (40700).........................................
13.0 Management Meetings (30703)..........................................
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DETAILS 1.0 Persons Contacted Inspection findings were discussed periodically with the below Long Island i
Lighting Company supervisory and management personnel.
W. Stieger, Plant Manager - LILCo T. Carrier, Instrument and Controls Engineer - LILCo i
C. Seaman, Quality Systems Manager - LILCo B. Germano, Licensing Engineer - LILCo Mike Pearson, Licensing Engineer - LILCo Lou Resnansky, Lead Stress Engineer - LILCo Kurt Ronis, Engineering Mechanics Section Head - LILCo K. White, Lead Instructor, Technical Support Training - LILCo M. Buring, Health Physics Engineer - LILCo The inspector also contacted other members of Operations, Radiation Protection, Maintenance, Quality Assurance, and Nuclear Operations Support.
2.0 Facility Activities 2.1 Summary The facility remained in cold shutdown throughout the inspection period.
Maintenance activities were focused on replacement of an Intermediate Range Monitor (IRM) detector, resolution of ASME code items, replacement of Agastat relays, dredging of the intake canal, and repair of Residual Heat Removal (RHR) testable check valve A0V-81A. Other routine mainten-ance and surveillance activities were also conducted. An operating pressure test of the reactor vessel was completed in January to retest ASME Class 1 joints repaired during the inspection period. The test was successful except for seal leakage identified on A0V-81A. The licensee was continuing repair work on this valve at the close of the inspection period. Problems requiring detailed or followup inspection are high-
-lighted-below.
2.2 ASME Code Deficiencies On January 12, 1989, the licensee found American Society of Mechanical Engineers (ASME) Code Class 2 bolting material utilized in an ASME Code Class 1 application.
The problem was identified during reassembly of a Class 1 joint in the Residual Heat Removal (RHR) head spray line. The joint had been disassembled for a local leak rate test of the head spray line isolation valves.
A LILCo Deficiency Report (LDR) was initiated to document the discrepancy.
An inspection of 26 ASME Code Class 1 bolted joints was conducted by the licensee. This represents all Class 1 joints at Shoreham except for those associated with the Control Rod Drive System (CRD).
Fasteners for
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CRD Class 1 joints are uniquely designed and are supplied by General Electric. The licensee concluded that improper fasteners could not have been used in the CRD Class 1 joints and chose not to inspect them.
The licensee inspection found five additional Class 1 joints with in-adequate bolting materials. All six unsatisfactory Class 1 joints con-tained ASME Code Class 2 bolting materials and one joint contained non-ASME nuts.
Further investigation revealed the fasteners for all six joints were installed in 1986 in conjunction with removal of the reactor vessel head under one Maintenance Work Request (MWR). The original bolting materials were damaged during disassembly in 1986 and were re-placed by the inadequate bolting materials.
Since discovery of this condition the licensee has replaced the inadequate bolting materials found in all six joints with ASME Code Class 1 materials.
In these applications, the inadequacy involved examination and testing.
The inadequate bolting materials met the American Society for Testing and Materials (ASTM) manufacturing standards required by the ASME Code Class 1 Bolting specifications but lacked required non-destructive ex-amination and impact testing.
The licensee determined the cause of this problem to be inadequate pro-cedural instructions.
Procedure SP 35.705.38 " Reactor Vessel Head In-sta11ation" was the controlling document used to install the inadequate bolting materials in 1986. Appendix 12.5 of the procedure specified replacement bolting materials per the appropriate ASTM standards, but did not clearly indicate that the replacement bolting had to also meet ASME Code Class 1 specifications.
The mechanics requisitioned and in-stalled the fasteners specified by the procedure.
The inspection conducted by the licensee was sufficiently comprehensive to assure that no other Class 1 bolted joints contain inadequate mate-rials. However, the adequacy of ASME Class 2 and 3 components replaced since construction is in question. Also, program changes to prevent recurrence of this problem in future ASME system maintenance need to be reviewed for adequacy. These concerns were expressed to the licensee and are unresolved pending licensee evaluation and appropriate action (89-01-01).
2.3 Agastat Relay Failures A common mode failure of Agastat relays installed in safety-related sys-tems at Shoreham yas identified by the licensee. The failure stems from a manufacturing defect which causes mechanical binding of the relays.
It was also found that a majority of Agastat relays installed in the facility have exceeded the manufacturer's recommended service life. The licensee committed to dispositioning all safety-related Agastat relays which are subject to these deficiencies prior to further power operation.
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The problem was found during performance of surveillance procedure SP'
44.656.02, " Reactor Vessel High Level Instrumentation Logic System Func-
-tional Test"..The procedure verifies operability of the feedwater pump /-
main turbine. trip' systems as required by Technical Specification.4.3.9.2.
'The trip _. systems function to.cause high reactor water _ level trips'of the feedwater pump turbines and of the main turbine. The trip system is con-figured in a 2 out of 3 logic and.is designed to cau.se a trip upon loss of power. During the. test,.two Type GP 120 VDC Agastat relays failed
.to function as required. The' relays are normally energized and de-ener-gize upon a high reactor water-level. signal, causing auxiliary contacts in the feed pump and main turbine trip circuits to.close. The first'
relay to fai1 was associated with the "B" channel..The' relay.had func-tioned properly upon de-energization; however, the' auxiliary contacts failed to re-open.upon circuit reset and re-energization of the relay.
This prevented resetting the~ feedwater pump."A" and main turbine trip circuits. The second relay, associated with the "C" channel, failed to close its auxiliary contacts upon de-energization. This resulted in functional failure of the feedwater pump "A" and main turbine trip cir-
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cuits. The two relays were replaced and the surveillance was success-fully completed.
-In 1984, premature failure of Agastat GP relays was-identified by the NRC as a potentially significant problem. This'was addressed in IE;In-formation Notice 84-20, " Service Life of Relays in Safety Related Sys-tems". The notice attributed.the failures to mechanical interference-resulting from post-mold plastic shrinkage of the relay casings. The problem was limited to Agastat GP series relays manufactured prior to 1977 by Amerace Corporation..The notice also documented qualified ser-vice lives for energized and de-energized Agastat relays at 4.5 and 10-years, respectively.
The licensee had been aware of these problems _with Agastat GP relays prior to issuance of IE Notice 84-20. This knowledge was gained through industry notifications and prompted the licensee to request the Architect Engineer (AE) to evaluate corrective actions. The AE performed an engi-neering survey of all Class IE Agastat GP relays used at Shoreham in-both the balance.of plant (BOP) and the Nuclear Steam Supply System (NSSS).
This totaled over 200 relays in various safety-related systems. The AE concluded, in a letter dated June 14, 1983, that the subject relays :
should be replaced prior to completion of the first refueling outage.
l The AE based its conclusion on a determination that failure of the relays, after long term usage, could impact the safe control and operation of r
the plant. The licensee s Independent Safety Engineering Group (ISEG)
reviewed the AE's survey and reached the same conclusions and recommen-dations.
In response, the licensee released, for implementation, Design Output Package.(DOP)84-004, to replace the relays. That DOP did not specify an implementation schedule but called for replacement of inoperable re-lays found during normal surveillance testing. The licensee could not
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produce for the inspector any documentation to support the shift to a l
" replace when fail" schedule instead of prior to the end of the first refueling outage. At the time the recommendations were made (1983), the first refueling outage was anticipated to occur in 1984 or 1985.
Licens-ing delays have extended the first refueling outage into 1990. The ad-ditional years represent one complete service life for relays that are normally energized and nearly one-half a service life for those that are normally de-energized. Although the licensee has not completed evalu-ation of these considerations, it is believed that a large percentage of Agastat relays installed in the facility have exceeded their qualified service life. Also, it is known that only a small percentage of the relays were replaced in accordance with 00P 84-04.
The licensec intends to dispostion the relays in question. This is to be accomplished by replacement or by analysis justifying extending the qualified service life. The licensee was continuing replacement activi-ties and final resolution of this issue at the close of the inspection period. The issue will remain unresolved pending final resolution (89-01-02).
3.0 Facility Tours (71707)
The inspector observed plant operations during regular, backshift,'and holiday tours of the facility. Backshift inspection was conducted on February 2, 1989, from 3:00 a.m. to 8:00 a.m.
Holiday inspection was conducted on February 13, 1989 (LILCo Holiday) from 8:00 a.m. to and 4:00 p.m.
Control room instruments were observed for correlation between chantels, pro-per functioning, and conformance with Technical Specifications. Alarm con-ditions in effect and alarms received in the control room were discussed with operators. The inspector periodically reviewed the night order log, tagout log, Operator logs, and bypass jumper log.
Logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication and equipment status.
No inadequacies were noted.
4.0 Plant Operational Events Reviews (71707)
4.1 Loss of Reactor Protection System (RPS) Bus "A" on January 24 A spurious trip of breaker 2B on the "A" RPS bus at 8:55 A.M. on January 24 caused a half-scram and initiation of the "A" Control Room Air Condi-tioning (CRAC) and "A" Reactor Building Standby Ventilation System (RBSVS) logic. The reactor was in cold shutdown with a reactor coolant temperature of 170 degrees F.
Plant operators reset the "A" scram signal after verifying the trip was spurious, and after switching the "A" RPS power supply to its alternate source.
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Inspector review determined that operator responses were appropriate.
Inspector review also verified that the plant response was proper, based
.l on a review of drawings ESK-11T4601, 11T4602, 11T4603 and Elementary Diagrams 1.63-96G, 1.63-089L and 1.61-16G. The inspector noted, however, that recovery actions revealed a degraded condition that warranted fur-ther follow-up.
RBSVS Train A isolation valve A0V-37A did not fully close. A0V-37A is a 72-inch damper in the discharge of the Reactor Building Normal Venti-lation System (RBNVS) exhaust fans. A0V-37A is upstream of, and in series with, "B" train isolation valve A0V-37B. The valves close upon initiation of their respective RBSVS trains and fail closed on a loss of air or power to the actuators. During normal operation, the RBNVS supply fans draw air into the reactor building and the RBNVS exhaust fans exhaust a slightly greater amount of air to the plant stack. That creates the vacuum required in the reactor building for secondary con-tainment operability.
Upon initiation of RBSVS, the RBNVS supply fans
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trip, the RBNVS inlet dampers close, and RBSVS dampers ADV-37A & B isolate the reactor building. The RBNVS exhaust fans then supply air to the refueling floor and the suction of the RBSVS exhaust fans. The RBSVS exhaust passes through filters and out the elevated release point.
Leakage past ADV-37A is a potential problem because the RBNVS exhaust fans continue to expel air through the leaking isolation valve. Such leakage is significant in the following two respects.
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Excessive reactor building vacuum may result (more than 1.0 inch of vacuum water gauge).
Post-accident flow through A0V-37A/B bypasses RBSVS filtration and
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the elevated release point, and could be an unmonitored ground level release.
Following RBSVS initiation, reactor building vacuum is normally about 0.4 inches of water gauge.
Following the initiation of RBSVS "A" on January 24, the reactor building vacuum approached 3.0 inches of water gauge.
The Control Room operators manually initiated RBSVS train "B" and ADV-37B closed, returning reactor building and vacuum to normal.
Following RBSVS restoration to standby, the A0V-37A seating surface was adjusted and cleaned.
Post-test actuation on 1/28/89 indicated that the valve continued to leak. The operator was lubricated and cycled several times locally.
Following this maintenance, the valve fully closed and maintained proper vacuum following initiation of RBSVS "A".
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l, A review of the maintenance history for A0V-37A revealed similar problems l
occurring almost yearly since 1984.
Seven Maintenance Work Requests (MWRs) have been initiated since 1984 to correct leakage problems as-sociated with A0V-37A.
Some of these were initiated following actuations of RBSVS.
The inspector discussed these indicators with the Maintenance Division Manager and with the Systems Engineer assigned responsibility for RBSVS.
The Systems Engineer had noted the problem and was intending to initiate action to perform an engineering review. The inspector noted that there is no one person or group of persons clearly assigned responsibility for identification of conditions such as the one evident here. MWR histori-cal data is readily available in a computer data base; however, it ap-pears that a lack of clear guidance on who is to monitor this data for equipment problems and trends can result in repeated maintenance on com-ponents without resolution of root problems. This concern was discussed with the licensee and will be considered during the next evaluation of licensee performance.
5.0 NPF-36 License Conditions 5.1 License Condition 2.C.14 Seismic and Dynamic Qualification (References: FSAR Section 3.10.
SSER 3, SSER 7, SSER 8)
License condition 2.C.14 (a) states: " Prior to exceeding five percent of rated power, the licensee shall complete the qualification, documen-tation, and installation of:
(1) Radiation monitoring system panels (Mark 1D11*PNL-117A&B)
(2) Radiation monitoring system pumps (Mark 1011*P-126, 134)."
The radiation monitoring system panels contain the channels for each of the two high range radiation monitors, which are mechanically isolated and electrically separated. The radiation monitoring system pumps supply sample air to the post-accident station vent monitors.
From January 5 to January 16, 1988, a specialist inspector in the NRC Region I office reviewed the seismic qualification documentation for the subject equipment. Attachment 1 to this report is a list of the docu-mentation reviewed. A discussion of the seismic qualification of the-major system components follows.
5.1.1 Control Room Cabinets The Class IE instrument cabinets (Stone and Webster mark number ID11*PNL-117A, B) located in the control room contain:
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Ratemeters 1 ea.
NIM RIC 2 ea.
Isolation Module 4 ea.
Recorder 1 ea.
Top Assembly 2 ea.
. Power Supply 2 ea.
The cabinet is a vertical single bay structure with overall dimensions of 90" high with a rectangular cross section 24" wide and 30" deep.
The inspector reviewed and verified the seismic analysis pre-
. pared by Kaman Instrumentation Company for the cabinets as
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Structural Model (for Ansys input)
The inspector. verified that the structural model included ap-propriate assumptions and boundary conditions and accurately
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reflected the geometry, dimensions and material properties of the cabinet.
The model consists of four components:
Basic cabinet (nodes10-199).
- Internal stiffening (nodes10-199)
Component rack (nodes 200-299)
Wire brackets (nodes 300-404)
The cover is fabricated from aluminum plates. All of these models were plotted by computer to verify accuracy in terms of their geometric configuration.
Seismic Environment
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The inspector reviewed the modal analysis used to determine the natural frequency of the cabinet. The inspector confirmed that the g values (accelerations) used for the equivalent static analysis were consistent with previous commitments to.
the NRC's office of special projects (letter from LILCo to NRC SNRC-866 April 15, 1983).
l The response spectra analysis showed that, at the elevation L
where the instrument cabinet is installed (elevation 63 feet in the Turbine / Control building), there is essentially no dy-namic amplification for components with a natural frequency greater than 12 Hz.
Since the natural frequency of the cabinet is 20.4 Hz, the equivalent static analysis technique is ac-
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1 Bolt Tie Down Calculation The cabinet tie down bolts were analyzed using reactive forces determined from the Ansys computer analysis. The analysis found that the eight 5/8 inch diameter A307 bolts are stressed below code allowable values.
Conclusion The analysis showed the 1E cabinet to be structurally adequate for its intended use in Shoreham Nuclear Power Station.
5.1.2 Auxiliary Pump Skid The auxiliary pump skid (Stone and Webster mark number 1D11*PNL-126, 134) supports the following components:
The motor starter assembly and support structure;
Base plate weldments; and,
Associated plumbing.
- The inspector reviewed the structural model for the motor starter assembly and the support structure to ensure that the physical configuration and material properties were incorpor-ated in a proper fashion for the Ansys computer program input.
Modal analysis showed that the lowest natural frequency of the structure is 65 Hz.
Because that is greater than 33 Hz, the structure is considered to be rigid and an equivalent static analysis was performed to determine the actual stresses. This is in accordance with IEEE Standard 334-1987 and NRC Regulatory Guide 1.100.
The resultant element stresses were found to be within allow-ables and demonstrated a comfortable design margin as summar-ized in table III of Kaman Report No. K-83-82 U(R).
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A hand calculatten had been performed to evaluate the base plate weldment. The inspector independently verified this calculation of the base plate's natural frequency and stresses.
The stress interaction analyses demonstrated acceptable factors of safety of 2.2 and 2.1 for the plate and the weldment, re-spectively.
The inspector also spot checked the stress interaction analyses for the anchor bolts and found them within code allowables.
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Plumbing and Wiring Analysis
The pump skid plumbing consists of 3/4 inch outside diameter
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by 0.065 inch thick stainless steel tubing. Also included is a flow meter, a hand-operated valve, and a pop-off valve.
The pop-off valve, tubing and fittings were qualified by tests conducted by Kaman and documented in Appendix G of report No.
K83-82V(R). The longest unsupported _ length of tubing was seismically qualified by static analysis with actual resultant stress below the allowable. The motor starter assembly and the pump / motor were qualit'ied by analogy and comparison to
tests successfully performed on similar components.
All these seismic qualifications.were performed in accordance to IEEE 344-1975, which is acceptable to the NRC.
5.1.3 Standby Vent Monitor The inspector verified that the sample cooling. system (P/N 952671-001) installed in the reactor building-standby vent gas high range effluent radiation monitor (P/N 450761-007, tag No.
D11*PNL-134) was seismically qualified in accordance to IEEE Standard 344-1975.
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'The cooling system consists of the following sub-assemblies:
l Cooler Winding assembly
Condensate tank
Connection panel box
Tubing and tube fittings
2 and 3 way solenoid valves a
Unistrut and mounting hardware
The inspector reviewed the following aspects of the structural analysist:-
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(1) The input data used to calculate the center of gravity, mass and other material properties.
(2) The modal analysis to extract the eigenvalues (natural frequencies) and eigenvector (mode shapes).
(3) Static analysis performed using Ig equivalent load for the three orthogonal directions (x, y, 2).
The results from the static analysis were spot checked to ensure that the resultant stresses are within allowables.
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Based on the above, the seismic analysis for the cooling system installed in the reactor building standby vent monitor (mark No. 1D11*PNL-134) supplied by Kaman Instrumentation Corp. meets i
the seismic requirements established in IEEE-344 and is ac-ceptable.
The inspector concluded that the licensee has provided acceptable seismic qualification for the subject radiation monitoring system components.
5.2 License Condition 2.C.12, Attachmant 3. Item H.
Emergency Diesel Generators, Procedures and Training License condition "H" of Attachment 3 to License NPF-36 states:
" Prior to operation at reactor power levels greater than 5%, the licensee shall complete in a timely manner acceptable to NRC staff, the development of suitable procedures and training to minimize the likelihood of operator errors that could result in EDG overload."
The inspector reviewed the licensee's actions to comply with this condi-tion and found them complete and adequate. The documents reviewed during the inspection are listed in Attachment 2 to this report.
Supplement 9 to NUREG-0420, " Safety Evaluation Report...Shoreham Nuclear Station," (SSER-9) paragraph 8.3.1.2.5 described the staff's conclusions on its review of licensee actions to preclude exceeding the Emergency Diesel Generator (EDG) qualified load. The staff found the procedures, training, and instrumentation for operation with a qualified load of 3300KW were acceptable with the following exceptions:
Annunciator windows were needed to clearly indicate the qualified
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load had been exceeded.
Certain procedures required additional changes or_ clarifications.
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The procedures are listed in SSER-9 and the required changes are described in licensee submittal SNRC-1150 dated April 4, 1985.
Completion of training which incorporated recommendations from the
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task analysis performed by General Physics.
The inspector verified the installation and operability of the annunci-ators. The in.spector reviewed the required procedure changes and found them to be in accordance with the commitments of SNRC-1150. The inspec-tor reviewed the lesson plans and training records to verify completion of the required training. The inspector noted that attendance records for five licensed operators were incomplete.
Further review and discus-sion revealed the discrepancy to be an administrative omissior. The
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licensee verified attendance through discussions with the five indivi-duals and documented this in a memorandum to file. No other discrepan-cies were noted.
Based on this review, the inspector confirmed resolution of all out-standing issues as described in SSER-9 paragraph 8.3.1.2.5.3.
This con-i firmation resolves item "H" of Attachment 3 to facility License NPF-36.
6.0 Preliminary Operational Readiness Review (71707/40500)
Operational readiness was reviewed by the Senior Resident Inspector from the Millstone Nuclear. Station. That inspector sampled operating activities for readiness to support plant startup and operation above 5% power. This effort was accomplished through plant tours, reviews of procedures and operating
records, and discussions with licensee personnel.
Items considered during i
the review along with the inspection findings are summarized below. Plant
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procedures used during the review are identified in Attachment 3 to this re-
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port.
The management of shift activities was reviewed based on interviews with shift and staff personnel. This review concluded there was an ample and. stable operating staff in all shift positions, except that the plant equipment
. operator position has experienced high turnover. Management attention to correct the problem is evident in the large number of operators in that posi-tion to compensate for the losses.
Generally good control of operator work
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schedules and no excessive use of overtime were noted.
Shift briefings and turnover activities were observed on several occasions and found to be thorough and orderly.
Daily staff meetings for reviewing plant status, establish parts availability, and prioritizing work schedules were found to be effective management tools for control of operating activities. The effectiveness of reviews performed.
by the plant review of operations committee (ROC) was verified by observation of meeting 89-02 and by independent inspector evaluation of the recommenda-tions and safety evaluations made by the committee. This aspect is discussed further in Detail 12.0 of this report.
Plant system operational and startup readiness status was verified based on a detailed control board walkdown with licensed operators.
Plant systems needed for power operations were operable and available, except as tagged out for short term maintenance and testing.
Valve lineup verifications were com-pleted on a sampling basis for the standby liquid control system, the reactor building normal and standby ventilation systems, and the hydraulic control unit and scram instrument volume portions of the control rod drive system.
Acceptance criteria for proper valve lineup determinations included a compari-son with plant procedures and drawings, and inspector judgement. No inade-quacies were identified.
Plant operator general knowledge of plant systems and conditions was verified during control room tours. Operator knowledge of specific plant activities and the status of equipment was also verified. This review also verified s
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proper operator response to offnormal conditions, operator knowledge of de-tailed plant design features, sufficient familiarity with reference drawings and procedures to research technical questions, and operator knowledge of procedures and administrative requirements for routine testing, maintenance and control of plant systems.
Review included interviews with different operators on three of the six operating shifts. The inspector found the operating staff professional and highly competent.
Proper implementation of administrative controls over operating activities was evaluated by review of tagging controls, of Technical Specification limiting condition for operation (LCO) tracking, of jumpers and lifted leads, and of the control of locked valves.
Plant safety system tagging controls were verified to be adequate through re-view of clearances 89-1-42, 89-1-46, 87-08-59, 88-7-83, 88-07-146, and 88-09-118. The review included a verification of proper placement or removal of selected tags. The inspector independently reviewed all outstanding 1988 and 1989 equipment clearances to assess the impact on operating equipment and to review the implementation of the licensee's program to disposition outstanding tagging orders greater than 60 days old. A similar review was completed for outstanding jumpers and lifted leads. This review verified the adequacy of licensee controls to review and close open requests that may impact system operability.
The control of locks of system valves was evaluated based on inspection of lock status and position for valves P42*04V-0131A and P42*04V-0128A. No inadequacies were identified.
Facility tours were completed to observe system status, plant conditions, and equipment operational readiness.
Equipment cleanliness was found exception-ally good. There was good control of work materials during and after comple-tion of work.
Equipment identification and labeling was good in all areas toured. No inadequate conditions were identified, but the following matter required follow-up.
Deficiency Tag 85-6206 dated 10/9/85 on by 'raulic control unit (HCU) 34-51 indicated the the "B" solenoid valve was c fective. The inspector noted that the HCU 34-51 soleniod valves were operating satisfactorily on January 10, 1989.
Licensee follow-up determined that the "B" solenoid valve had been repaired under maintenance work request 85-6206 on 11/5/85 and that the de-ficiency tag should have been r'emoved at that time. The tag was removed.
The inspector concluded that this was an isolated finding and was not indica-tive of a programmatic problem.
Plant housekeeping and fire protection were reviewed based on observations of equipment and conditions. The inspection included interviews with fire watch personnel and review of fire permits 89-24-7, 28-7, 29-7, 30-7, 37-7, 63-7, and 196-7. The implementation of compensatory measures for inoperable equipment in the "C" battery room was verified to be proper. A number of areas require ongoing fire watches as a result of inoperable fire dampers.
The status of the program was reviewed with licensee Engineering and Compli-ance personnel. The number of areas that require compensatory measures was
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found to be well tranaged by the licensee. Design changes are tentatively scheduled for completion in 1989 to reduce the'need for compensatory measures.
Overall, this inspection verified proper implementation of the fire protection program.
The inspector interviewed the onsite Quality Assurance (QA) and Quality. Con-trols (QC) supervisors to review the scope and results of audit and surveil-lance findings for Operations.
The inspector also reviewed QA audits NB-88-02 and NQA-88-20. The audits and surveillance were found to be performance-based operating and training activity reviews that verified effective program implementation. Qualified technical specialists were used as needed in the audits. A notable accomplishment of the training audit was a review of the Emergency Opera. ting Procedures (E0Ps), including a verification of the E0P calculational bases. The QC group also trends surveillance findings to iden-tify weaknesses. A notable example of this effort was Corrective Action Re-quest 88-05 dealing with maintenance work practices and material controls.
In general, QA audits and QC surveillance functions were found to be effec-tively used to verify the satisfactory completion of operating activities,
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and to identify and correct problems.
Based on the observations and findings discussed above, the inspector con-cluded that the plant systems, facility programs and procedures for operating activities, and the operating staff are ready to support power operation.
7.0 Facility Inspection Tour by NRR Director Dr. Thomas Murley, Director of the Office of Nuclear Reactor Regulation (NRR),
visited Shoreham on January 24, 1989. The purpose of the visit was to perform a walk-through inspection and to review the licensee's provisions for post-accident venting of the primary containment.
Dr. Murley toured the control room and reactor building including the drywell, I
accompanied by the NRC Region I Section Chief of Projects Section IB and the NRC Senior Resident Inspector.
Systems and components necessary for post-accident venting of the containment were observed.
No discrepancies were noted during the tour. Dr. Murley found general facility appearance and equipment labeling to be good.
Following the inspection tour, the licensee gave a brief presentation regard-ing the strategies for post-accident primary containment pressure control.
The discussion focused on post-accident pressure control following accidents
.which are beyond the facility design basis. These are summarized below.
The design basis loss of coolant accident (DBA LOCA) analysis predicts a maximum post-accident containment pressure of 47 psig. Drywell and suppres-sion pool sprays are predicted to be capable of adequately controlling this pressure. During a hypothesized severe accident scenario that exceeds the plant design basis (Anticipated Transient Without Scram, Station Blackout),
containment pressure is hypothesized to exceed 47 psig. At 60 psig the Emer-gency Operating Procedures direct the operators to vent the primary contain-ment via the Reactor Building Standby Ventilation System. At containment
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j pressures above 60 psig the drywell floor seal would begin to deform, allowing leakage from the drywell to the wetwell airspace. That bypasses the scrubbing and condensing effect of the suppression pool. Without the effect~of the
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suppression pool, containment pressure could rise and lead to containment failure (predicted to occur if pressure reaches 138 psig).
Containment vent-ing at 60 psig functions to minimize bypass leakage and thus mitigate the pressure rise and preclude containment failure. The two six-inch lines used to vent the containment can pass up to 1% of the decay heat load, which is consistent with the recommendations of the Boiling Water Reactor Owners Group Guidelines.
Following this presentation, the discussions focused on elements of the lic-ensee's Probabilistic Risk Assessment (PRA) including risk profiles repre-sented by human error. These discussions were informative in nature.
8.0 Allegations (92702/92720)
The inspector investigated an allegation concerning the licensee's General Employee Training (GET) program.
It was alleged that certain employees had net received adequate GET training prior to working in the Radiological Con-trols Area (RCA).
Station Procedure SP 12.014.03, " General Employee Training," defines the GET programs at Shoreham. These are Level I, Level II, NRC Level II, Visitor Training Level I, and Visitor Training Level II.
Levels I, II, and NRC II satisfy training requirements for unescorted access to the facility.
Levels I and II require classroom instruction followed by an examination. Certain persons may forego classroom instruction if they pass a comprehensive exemp-tion examination with a score of greater than 80%.
Visitor Level I satisfies requirements for escorted access to the protected area excluding the RCA.
Visitor Level II satisfies requirements for escorted access to the protected area including the RCA. Although persons with Visitor Level II training may enter the RCA, they may not enter or work in areas covered under Radiation Work Permits (RWPs) without special authorization from the Health Physics En-gineer (HPE). Additionally, the HPE's authorization is required for persons who intend to work in the RCA on a continuing basis. This latter requirement is not set forth in the procedure but is an administrative control used by the HPE to limit RCA access by persons with minimum radiological competence.
Visitor Levels I and II provide basic instruction on station layout and pro-cedures and are intended for new or temporary employees who are waiting to receive Level I or II classroom training.
Examinations are not required for completion of the visitor programs.
The allegers commenced employment at the station in October 1988. They com-pleted Visitor Level II GET training but were not allowed access to the RCA because they were not expected to work there on a continuing basis. The al-legers were then given additional health physics (HP) training beyond what is normally obtained in Visitor Level II. This additional training consisted of a 2.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> lecture. The allegers were also given an HP study guide and were told they would take the GET Level II exemption examination on November 7, 1988. This allowed them a few days to study the guides. The allegers were
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also told they would receive the GET Level II classroom training in late November. The allegers took the exemption examination. All scored greater
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than 70%, but only one scored greater than 80%. Based on these examinations, the HPE waived his administrative restriction and allowed the allegers es-corted access to the RCA but not to RWP controlled areas.
The allegers began working in the RCA. This continued until they were informed that the Level II classroom training scheduled for late November had been rescheduled for
"sometime in early 1989." The allegers became concerned that they had not received adequate GET training and brought this concern to the attention of the Senior Resident Inspector. The allegers claimed they were improperly exempted from classroom training based on the exemption examinations because the procedure required a score of greater than 80% to be exempt and they did
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not meet this requirement.
The inspector reviewed the allegation along with the training and qualifica-tion records of the allegers. These were compared with the procedural re-quirements of SP 12.014.03.
No procedural or other inadequacies were noted.
The exemption examinations were administered to assess the allegers' radio-Togical competence.
The results were used by the HPE to grant escorted access to the RCA. This control was administrative. By procedure, the allegers could have obtained continuing escorted access to the RCA without taking the exemption examination.
The 80% criterion is applicable for exemption from the GET level II classroom training.
The allegers were not granted such an exemption and completed the Level II classroom training in late December 1988.
In summary, the inspector found no violations, inadequacies, or unsafe radio-logical practices related to the GET qualification of the allegers. The lic-ensee's administrative control of access to the RCA and of granting waivers to this control were found conservative and appropriate. The allegation is closed.
9.0 Observation of Maintenance Activities (62703)
The inspector observed and reviewed selected portions of preventive and cor-rective maintenance to verify compliance with regulations, use of administra-tive and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest.
The replacement of an in-core flux monitor Intermediate Range Monitoring (IRM)
detector assembly by Instrument & Control (I&C) technicians was observed.
The job required the support of operations, health physics and quality control personnel.
Departmental interfaces appeared adequate.
Prior to maintenance under the reactor vessel on the failed detector, the NRC inspector verified that the specific drive mechanism for the IRM was properly tagged out-of-service, the reactor was in cold shutdown and depressurized, and a Radiation Work Permit (RWP) was issued to perform the work.
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The work activities associated with the removal and replacement of the neutron detector was performed under Maintenance Work Request (MWR) 89-0257 per sta-tion procedure SP 35.703.01, "In-Core Flux Monitor (SRM/IRM) Removal and In-stallation." The particular detector, IC51*410 IRM-012C, failed during earlier testing under MWR 89-0128. The Watch Engineer authorized the work to begin on January 16, 1989.
The NRC inspector examined the licensee's administrative control procedures for the task being performed.
In addition, the maintenance work request package was reviewed. The procedures and maintenance package were found ade-quate for the maintenance.
While observing the in process use of SP 35.703.01, the NRC inspector noted that the licensee was using two different approved revisions of vendor tech-nical manual GEK 13962 during IRM replacement. The installation work by the technicians was being conducted to revision J; management oversight by the I&C foreman was conducted to revision G.
The QC inspector providing coverage was asked about this. The use of two different revisions of the vendor manual at the work station could not be explained.
Even though the licensee failed to adhere to station procedure SP 12.019.08, " Station Approval and Control of Vendor Documents," there was no impact on IRM replacement activities or safety, since all work was found to be performed to the latest revision of the vendor manual.
Based on these reviews, discussions, and visual examinations, the inspector concluded that the maintenance work was acceptable.
The inspector also monitored maintenance activities associated with the repair of the RHR testable check valve A0V 81A and the replacement of bolting mate-rials-in ASME Class 1 bolted joints. No discrepancies were identified.
10.0 Maintenance Program Implementation (62700)
A review of the licensee's maintenance programs was conducted. The inspector reviewed administrative controls; interviewed maintenance, Instrument and Control (I&C), and work planning / scheduling personnel; and observed in process maintenance work activities. lhe backlog of outstanding Maintenance Work Requests (MWRs) was examined to determine the impact, if any, on safety-related equipment operability.
In addition, Quality Assurance / Quality Control (QA/QC) involvement with Shoreham maintenance activities was evaluated to determine whether the licensee is implementing an effective program.
Maintenance Work Request Review The maintenance Work Request (MWR) program provides administrative controls for the identification, performance, and documentation of plant maintenance on safety-related and non-safety-related equipment and components.
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l MWRs are tracked on a computer-based system maintained by the Work Pla'nning and Scheduling Section (WPS).
Reports are prepared which trend several j
parameters associated with the MWR program. MWR trend reports are issued to
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plant management and individual sections on a weekly and monthly basis. These reports are used to assess the effectiveness and efficiency of the program.
A review of the December 1988 Monthly MWR Trend Report revealed that the lic-ensee has a total of 1605 MWRs outstanding. Approximately 1300 MWRs cannot be resolved until sufficient steam is produced to test the High Pressure Coolant Injection System and Reactor Core Isolation Cooling System.
The licensee is successfully reducing the backlog of MWRs.
In 1988 there were i
a total of 3857 MWRs written and 4689 MWRs closed. The current trend indi-cates that approximately 73 MWRs are being issued each week, while 105 MWRs are being closed. The station goal is to reduce and maintain the MWR backlog to approximately 1000 MWR's.
i Quality Assurance / Quality Control Overview (QA/QC)
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The QA/QC organization has approximately 35 qualified licensee personnel.
In addition, the licensee has 15 contractor nanagement/ supervisory personnel on site to provide internal, independent quality oversight activities neces-sary to support normal operations and plant activities. No QA/QC staffing inadequacies were noted.
Interviews were conducted with various QA/QC personnel. The individuals in.
terviewed were technically qualified, with sound experience in the particular areas they were auditing.
Several individuals within the licensee QA organi-zation had previously worked in the maintenance division or engineering or-ganization at Shoreham. QA/QC is actively involved in identifying weaknesses and problems in the maintenance area.
Review of recent QA/QC audits, sur-veillance deficiency reports, and corrective action requests (CARS) indicates that quality oversight of maintenance is technically and performance oriented.
During December 1988, QA/QC issued two Corrective Action Requests (CARS) re-lated to maintenance. CAR 88-04 was issued on December 8, 1988 due to several deficiency reports and priority one preventive maintenance activities sur-passing scheduled due dates without being extended or deferred as required by procedure.
CAR 88-05 was issued on December 28, 1988 for improper work practices and incorrect material utilization.
Management is aware of the adverse quality trend in maintenance indicated above, and has initiated investigation into the probable cause and necessary corrective action.
In addition, a meeting was held on January 19, 1989 with Maintenance, QA/QC,.and the Vice President-Nuclear Operations to gain a better understanding of the deficiencies denoted in CAR 88-05. Management has been receptive and responsive to the QA/QC concerns / findings. This matter will be re-examined incident to routine inspection of maintenance.
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The inspector observed portions of surveillance tests to assess performance in accordance with approved procedures and Limiting Conditions of Operation, removal and restoration of equipment, and deficiency review and resolution.
The followir.g tests were reviewed:
SP 22.009.01, " Reactor Pressure Boundary Leak Test"
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SP 44.656.02, " Reactor Vessel High Level Instrumentation Logic System
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Functional Test" No inadequacies were noted.
12.0 Committee Activities (40700)
The inspector attended meeting 89-02 of the plant Review of Operations Com-mittee (ROC) on January 10, 1989 to observe review of proposed changes to station procedures.
Committee administrative requirements were met for the meeting. The ROC discharged its functions in accordance with, regulatory re-quirements.
Procedures reviewed were available to ROC members and there was a good discussion by the committee regarding the need for and acceptability of proposed revisions.. Reviews were characterized by a conservative and probing approach to potential safety issues. The ROC chairman lead discus-sions on each agenda item.
Further reviews or presentations to ROC on con-troversial matters were requested as necessary. The inspector noted that all ROC recommendations for approval were appropriate. Two matters discussed during meeting 89-02 warranted further inspector follow-up, as summarized below.
Changes to surveillance procedures SP 24.119.04-1 and 24.202.03-1 were recom-mended to better test the suppression chamber suction check valves for the RCIC (Reactor Core Isolation Cooling) and HPCI (High Pressure Coolant Injec-tion) systems, respectively. The revised procedures would better assure the pump suction check valves were functionally tested in both the forward and reverse flow directions. The ROC questioned whether the original procedure performed an appropriate check of the test valves during past tests and whether the matter was reportable to the NRC. A ROC open item was assigned.
The matter was then addressed in a January 17 memorandum (OPE-89-008) to the ROC from the Operating Engineer.
Licensee review concluded that valve tests in both the old and the revised procedures were in full compliance with the inservice testing program and no reportable condition occurred.
Inspector review of tlie licensee's conclusions and of the ASME Section XI test program identified no inadequacies.
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Another matter addressed by the ROC was a proposed change to the SP 24.402.01 I
functional test of the post-LOCA Hydrogen Recombiners. The revised test method would change the recombiner suction path from the drywell to the sup-pression chamber (SC) to preclude pressurizing the SC during recombiner func-tional tests. The ROC questioned whether there was a need to assure a peri-odic test of the drywell flow path, but accepted the revised test method on the basis there was no technical specification requirement to verify a minimum flow to the recombiners from the drywell.
The inspector noted that the recombiner test plan in FSAR Section 6.2.5.4 includes a periodic verification that the blowers operate at a flow rate of greater than 60 scfm. While not explicitly stated, the intent of this test specification would appear to require verification that the recombiner suction path from the containment was operable. Conformance with the FSAR is ad-dressed by acceptance criterion 9.3 of SP 24.402.01. This matter was dis-cussed with the Operations Staff and the Assistant Plant Manager on January 12. The licensee stated that the SP 24.402.01 test method would be revised as necessary to assure it continues to demonstrate the drywell flow path was acceptable as part of the operability demonstration of the recombiner system.
The inspector had no further question on this matter.
Overall, the inspector observed a thorough discussion of matters brought be-fore the ROC, and a good regard for safety in the committee deliberations.
No inadequacies were identified.
13.0 Management Meetings (30703)
Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings was also dis-cussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspection. No written material was given to the licensee during the inspection period.
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ATTACHMENT 1 The following documents were considered during the review of License Condition 2.C.14.
1.
Emergency Radiation Monitoring System Seismic Analysis of the Class IE Control Room Cabinet Kaman Report No. K-83-1-4(R), Revision B; June 7,1983.
2.
Seismic Analysis of the Auxiliary Pump Skid Kaman Report No. K-83-82-4(R);
September 13, 1983.
3.
Seismic Vibration Testing of 226S Recorder and 202S Shelf for Class IE Quali-fication Per IEEE 344-1975, the Foxboro Company QA Lab. Test Report T8-6013, Revision A; February 1979.
4.
Seismic Test Report of the Shoreham Heat Trace Skid and Recorder Power Supply Transformer, Kaman Report No. K85-154(R); February 4,1985.
5.
Seismic and Environmental Qualification Summary for Kaman Instrumentation Corporation Post Accident Radiation Monitoring System for The Long Island Lighting Company, Shoreham Nuclear Power Station Unit 1, Volume IV, Kaman Report No. K-83-198 U(R); January 30, 1984.
6.
Seismic and Environmental Qualification Summary Report for Kaman Instruments-tion Corporation Post Accident Monitoring System Equipment for Long Island Lighting Company, Shoreham Nuclear Power Station Unit 1, Volume III, Kaman Report No. K-83-189 U(R); January 30, 19C4.
7.
Seismic and Environmental Qualification Summary Report for Kaman Instruments-tion Corporation Post Accident Monitoring System Equipment for Long Island Lighting Company, Shoreham Nuclear Power Station Unit 1, Volume I, Kaman Re-port No. K-83-189 U(R); January 30, 1984.
8.
Seismic and Environmental Qualification Summary Report for.Kaman Instruments-tion Corporation Post Accident Monitoring System Equipment for Long Island Lighting Company, Shoreham Nuclear Power Station Unit 1, Volume II, Kaman Report No. K-83-189 U(R); January 30. 1984.
9.
IEEE Qualification Test Report for Kaman Instrumentation Digital Radiation Monitoring System Model KEM-P Process Monitoring Micro Computer AETC Test Report No. 16435-A, Revision 1, Volumes I & II.
10.
IEEE Qualification Test Report for Kaman Instrumentation Digital Radiation Monitoring System Model KMPIG-HRN-MF Process Monitoring Volumes I & II.
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k ATTACHMENT 2 The following documents were considered during the review of License Condition.
2.C.12, Attachment 3, Item H.
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Supplement 9 to NUREG-0420, " Safety Evaluation Report... Shoreham."
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NRC Inspection Report 50-322/85-30.
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SNRC Letter 1150 dated April 4,1985.
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SNRC Letter 1169 dated May 6,1985.
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SP 29.023.01, 'Revi sion 9, "RPV Control."
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SP 29.015.01, Revision 12, " Loss o'f Offsite Power."
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SP 29.010.01, Revision 8, " Emergency Shutdown."
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SP 23.307.01, Revision 27, "TDI Emergency Diesel Generators."
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SP 29.023.03, Revision 14, " Primary Containment Control."
10.
Lesson Plans and attendance records for License Requal Week 85-05.
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ATTACHMENT 3 The following plant procedures were considered during the review of plant startup readiness.
12.002.01, Station Organization & Personnel Responsibilities
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12.003.02, Station Overtime Policy
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12.004.01, Review of Operations Committee
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12.009.03, Report of Abnormal Conditions & Limiting Condition of Operation
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12.011.01, Station Equipment Clearance Permits
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12.013.04, Removal & Return of Safety Relates Components to an Operable Status
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12.023.01, Station Housekeeping
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12.035.01, Control of Lifted Leads and Jumpers
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21.004.01, Main Control Room - Conduct of Personnel
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21.007.01, Control of Operations Section Locks and Keys
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23.123.01, Standby Liquid Control
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