IR 05000277/1986019
| ML20214U282 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 11/25/1986 |
| From: | Gallo R, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20214U213 | List: |
| References | |
| 50-277-86-19, 50-278-86-20, IEB-80-10, IEC-80-14, IEC-81-01, IEC-81-05, IEC-81-07, IEC-81-1, IEC-81-5, IEC-81-7, NUDOCS 8612090211 | |
| Download: ML20214U282 (29) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/19 & 50-278/20 Docket No. 50-277 & 50-278 '
License No. OPR-44 & DPR-56 -
a Licensen: Philadelphia Electric Company 2301 Market Street '
Philadelphia,. Pennsylvania 19101 Facility Name: Peach Bottom Atomic-Power Station L' nits 2 and 3 Inspection At: Delta,-Pennsylvania :
Inspection Conducted: September 27 - November 7, 1936 i Inspectors: T. P. Johnson, Senior Resident Inspector J. H. Williams, Resident Inspector R. J. Bailey, Physical Security Inspector ,
A. G. Krasopoulos, Reactor Engineer :
P. K. Eapen, Chief QA Section A. E. Finkel, Lead Reactor Engineer Reviewed By: Are*:7 / /[p#/f(J H. Wilifams, Resident Inspector
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date Approved By: M #f2fhp Ilobert M. Gallo
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d&te Chief, Section 2A, DRP Inspection Summary: Routine, on-site regular and backshift resident and specialist inspection (135 hours0.00156 days <br />0.0375 hours <br />2.232143e-4 weeks <br />5.13675e-5 months <br /> Unit 2; 133 hours0.00154 days <br />0.0369 hours <br />2.199074e-4 weeks <br />5.06065e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, activities, maintenance, and outstanding item Results: Two shutdowns and one auto scram occurred on Unit 2. Two auto scrams and one manual scram occurred on Unit 3. A review of GE type AK-F-2-25 breakers determined that no problems exist, and the licensee has an adequate corrective / preventive maintenance program in place. Potential tampering with the 3C (Unit 3) SLCS pump breaker remains unresolve Licensee compensatory measures associated with the self identified non-conforming conditions of 10 CFR 50, Appendix R were reviewed. The cause of the apparent uncoupling of control rod 10-47 (Unit 3) remains unresolve A review of PORC and NRB activities determined that members displayed a good questioning approach and an excellent perspective of nuclear safet [
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DETAILS Persons Contacted J. B. Cotton, Superintendent Pla'nt Services R. S. Fleischmann, Manager,. Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Hemith Physicist J. 'F. Mitman, Maintenance, Engineer D. L. Oltmans, Senior Cheitist '
F. W. Polaski, Outage Planning Engineer S. R. Roberts, Operations Enginaer
- D. C. Smith, Suoerintendent Operations J. E. WinzenriedlStaff Engineer Other licensee employees were, also contacte *Present at exit interview on site and for summation of preliminary finding ' Plant Status '
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2.1 Unit 2 Unit 2 began the inspectibt period at full power. On September 29, 1986, the unit was shut down'due to water contamination of the turbine electro-hydraulic control (EHC) system oil (see Detail 4.2.1).
The EHC system was returned to service and the unit restarted on October 9, 1986. The unit auto scrammed on low main condenser vacuum on October 13, 1986 (see detail 4.2.4). The unit restarted the same day. On October 15, 1986, the unit was shut down to repair two condensate pumps and to perform other maintenance. The unit restarted on October-19, 198 The unit remained at or nea'r full power the remainder of the inspection period except for load drops for control rod pattern changes, for condenser water box leak testing, and for a unit runback that occurred on November 3,1986 (see detail 4.2.6).
2.2 Unit 3 Unit 3 began the inspection period at full power. On October 7, 1986, the unit auto scrammed on low reactor water level (see detail 4.2.2). The unit restarted on October 8, 1986. On October 30, 1986, the unit was shut down by a manual scram when a resin injection occurred into the reactor vessel (see detail 4.2.5). The unit scrammed during restart on November 4,1986 (see detail 4.2.7). The unit was restarted on November 5,1986, however a control rod coupling problem delayed power operation until November 7, 1986 (see detail 4.2.8).
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3 Previous Inspection Item Update 3.1 (Closed) NRC Bulletin 80-10 (277/80-BU-10; 278/80-BU-10).
Contamination of non-radioactive systems leading to potential unmonitored releases. The licensee responded to NRC Bulletin 80-10 in letters dated July 2, 1980; October 21, 1981; and January 29, 1982. NRC Inspections 277/82-16, 278/82-16; and, 277/86-25, 278/86-24 reviewed these licensee responses. Bulletin 80-10 remained open pending licensee completion of items (3) and (4). These items were addressed in administrative procedure A-4, PORC Procedure. The inspector reviewed A-4, Revision 2 Section A.4.q of procedure A-4 implements the requirements of items (3) and (4) of Bulletin 80-10 as follows: (a) to restrict operation of a contaminated non-radioactive system; and, (b) to perform a safety evaluation. Based on inspector review of licensee response letters referenced above, NRC Inspections referenced above, review of procedure A-4, and discussions with licensee engineers, NRC Bulletin 80-10 is close .2 (Closed) Inspector Follow Item (277/80-33-02; 278/80-26-01). Review long term solution to the off gas process radiation monitor (0G PRM) problem. In November 1980 (Unit 2) and again in October 1983 (Unit 3) the OG PRM system was out of service due to moisture in the sample lines. The licensee determined that the Unit 3 design was better than the Unit 2 design due to sloping sample line drains. Thus, MOD #623 was performed on Unit 2 in April 1981. The entire off gas system was upgraded in 1985 for Unit 2 with MOD #897 (ambient charcoal holdup system). MOD #897 is scheduled for Unit 3 in the 1987 refueling outag The inspector reviewed recent operating history (1984 thru 1986) including a review of LERs. No evidence of OG PRM problems due to moisture were noted. Also, discussions were held with licensee engineers. The inspector reviewed OG PRM operating procedures, sur-veillance procedures, and P& ids; and performed a walkdown of various portions of the Unit 2 and 3 OG PRM system. On October 1, 1986, the inspector observed a Unit 3 off gas vial sample per ST 7.6.1, "Quan-titative Analysis of Gamma Emitters in Off-Gas". During the ST observations, the inspector discussed the OG PRM system operation with the licensee technicians. No unacceptable conditions were noted. The inspector will continue to monitor OG PRM system performance. Based on the above, the inspector follow item is close .3 (Closed) Unresolved Item (277/85-15-03). Plant modification (MOD)
- 514N not PORC approved. MOD #514N was performed in 1979 to splice an instrument cabl PECo corrective action audit #AP- 86-04 determined that PORC meeting #79-080 reviewed and approved MOD #514 The unresolved item is close .4 (Closed) Unresolved Item (277/83-10-02; 278/83-10-02). Revise response time procedures to allow some flexibility of recorder speed and to better document calculations. The licensee revised the procedures, surveillance tests (ST)-14.3,14.4,14.11, and 14.1 These revised STs were reviewed in NRC Inspection 277/83-30. In
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i addition, the unresolved item was reviewed by Electric Production QA during audit #AP-85-105 and by PORC at meeting #86-042. The inspector reviewed the audit report and PORC meeting minutes. The licensee found that the method of determining response time, as revised in 1083, was adequate and conservative. The inspector reviewed the most recently completed ST-14.4 and ST-14.11 performed on Units 2 and 3. No unacceptable conditions were noted. Based on the licensee's analysis and inspector reviews, the unresolved item is close .5 (Closed) Inspector Follow Item (277/86-12-20; 278/86-13-20). Revise procedure A-12.2, " Control of Combustibles", to include motor vehicles in the power block. On June 26, 1986, the inspector noted an unattended parked truck on the 135 foot elevation of the Unit 2 .
Reactor Building. When informed, the licensee took immediate corrective actions and committed to revise procedure A-12.2 as appropriate. The licensee issued a memorandum on September 19, 1986, to describe and explain the newly approved procedure on motor vehicles in the Power Block. The inspector verified that adequate control of motor vehicles was included in A-12.2, Rev. 4, " Control of Combustibles", dated October 6, 1986. The inspector concluded that the licensee had addressed the fire protection aspects of motor vehicles in a thorough manner. The inspector follow item is closed, t
3.6 (Closed) Unresolved Item (277/85-44-08). ST 12.8 " Recirculation System Baseline Data - One and Two Loop Operation", was not performed when Unit 2 started up in July 1985. The reason for missing the surveillance test was unresolved. The test was done after it was brought to the licensee's attentio Equivalent baseline data on jet pump performance was collected during the 1985 startup. This was part of the acceptance testing for the recirculation system pipe replacement modification (MOD 1278). The reason for missing the surveillance test was determined to be lack of an adequate management system to insure performance of all tests. The licensee took actions to increase management involvement and improve the surveillance test program. Administrative Procedure A-43, " Surveillance Testing System" was revised to direct management attention to tests which are in their grace period or overdue so that steps will be taken to complete the test. The inspector reviewed the changes to A-43. The revised procedure appears to adequately address the problem of not performing some ST's. The inspector had no further questions at this tim This item is close .7 (Closed) Violation (278/85-33-02). The licensee failed to manually test all main steam relief valves during operating cycle 6 (September 1983 t6 augh July 1985) as required by Technical Specification 4.6.0.4. The licensee responded to the violation in January 198 Failure to properly follow an administrative procedure was the reason for the violation. The Operations Engineer issued a memorandum to shift operating personnel on handling partial tests in accordance with procedure. The inspector reviewed the memorandum to the shift
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personnel. Surveillance Test 10.4, " Relief Valve Manual Actuation" performed on Unit 3 on March 5, 1986, was also reviewed. This test was completed satisfactorily. No examples of missed tests due to partial testing have been observed since the violation was cite The inspector had no further questions. The violation is close . Plant Operations Review 4.1 Station Tours '
The inspector observed plant operations during daily facility tour The following areas were inspected:
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Control Room
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Cable Spreading Room
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Switchgear and Battery Rooms
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Reactor Buildings
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Turbine Buildings
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Radwaste Building
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Recombiner Building
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Pump House
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Diesel Generator Building
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Protected and Vital Areas
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Security Facilities (CAS, SAS, Access Control, Aux SAS)
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High Radiation and Contamination Control Areas j
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Shift Turnover 4. Control Rohm and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specification Presence of a senior licensed operator in the control room was verified frequentl Control Room formality including access control, operator behavior and environmental noise control, was reviewed routinely. The licensee controls access to the control room by requiring non-operational personnel to use the
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north (Unit 3) door; thus, minimizing the traffic in the l shift superintendent's office area. Recent utilization of chains across the north and south access to the control room complex area (i.e., control boards) has resulted in minimizing traffic and noise. Permission of an on-shift
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licensed operator is re' quired to enter the control board i are No evidence of unauthorized reading material. nor
the use of radios was noted. The background noise in the control room associated with the paging system was identified in a previous inspection (open item 277/86-12-05; 278/86-13-05). The licensee is planning modifications to !
reduce background noise associated with the paging syste l
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4. The inspector frequently observed that selected control room instrumentation confirmed that instruments were operable and indicated values were within technical specification requirements and normal operating limit ECCS switch positioning and valve lineups were verified based on control room indicators and plant observation Observations included flow setpoints, breaker positioning, PCIS status, and radiation monitoring instrument .1.3 Selected control room off-nort..a1 alarms (annunciators)
were discussed with control room operators and shift supervision to assure they were knowledgeable of alarm status, plant conditions, and that corrective action, if required, was being taken. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition .1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personnel. No un-acceptable conditions were observe .1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compliance with administrative procedures and regulatory guidance. No inadequacies were identifie .1.6 The inspector observed the main stack and both reactor building ventilation stack radiation monitors and recorders, and periodically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurre No inadequacies were identified.
- 4.1.7 The inspector observed control room indications of fire detection instrumentation and fire suppression systems, monitored use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment station One regional inspector reviewed the interim compensatory measures established by the licensee for the non-conforming conditions identified during the 10 CFR 50, Appendix R re-evaluatio The interim compensatory measures by the licensee include 2 to 3 continuous fire watches in areas where detection systems do not exist (primarily manholes) and eight roving fire watches, six of whom patrol areas where safe shutdown equipment is not protected in accordance with the require-ments of 10 CFR 50 Appendix R section III.G. The remaining two fire watches patrol the fire areas adjacent to those
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1 containing unprotected safe shutdown components for con-servatism. The fire watch functions include watching for fires in the incipient stage and identifying and eliminating hazardous conditions such as hot work or accumulation of combustible The inspector performed a walkdown of the affected areas using the prepared fire watch routes. The review also included the fire watch procedures and the training plans for these watche With regard to training, the licensee explained that the West Conshohocken Fire Academy will provide on-site training which will include hands on practice, for each fire watch. Additional classroom training will be provided by the station's fire protection coordinato The inspector determined that the licensee's compensatory measures will substantially improve the fire protection afforded to safe shutdown systems. Should a fire develop it should be quickly detected and suppressed. By controlling hazardous processes, the use of ignition sources and pre-venting the accumulation of combustibles, the probability of a fire is minimize No unacceptable conditions were note . The inspector observed overall facility housekeeping i conditions, including control of combustibles, loose trash and debris. Cleanup was spot-checked during and after maintenanc Plant housekeeping was generally acceptabl . The inspector observed the nuclear instrumentation subsystems (source range, intermediate range and power range monitors) and the reactor protection system to verify that the required TS channels were operabl .1.10 The inspector frequently verified that the required TS off site electrical power startup sources and emergency on-site diesel generator; were operabl .1.11 The inspector monitored the frequency of in plant and control room tours by plant and corporate management. The '
tours were adequat .1.12 The inspector verified operability of selected safety related equipment and systems by in plant checks of valve position, control of locked valves, power supply availability,
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I operating procedures, plant drawings, instrumentation and breaker position. Selected components were visually l inspected for leakage, proper lubrication, cooling water supply, operating air supply, and general conditions. No
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significant piping vibration was detected. The inspector reviewed selected blocking permits (tagouts) for conformance to licensee procedures. Systems checked included Unit 2
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and 3 core spray systems. During the core spray system
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walkdowns, the inspector noted that the 2D, 3C, 3B, and 3D core spray minimum flow. valves and motor operators have different supports than the remaining four valves (2A, 28, 2C and 3A). The inspector discussed this with the licensee, who stated that MOD #842 was currently underway to change the seismic supports for all eight valves. The inspector had no further questions at this time. No violations were identifie '
4.2 Followup On Events Occurring During the Inspection 4. Unit 2 Shutdown on September 29, 1986 The licensee determined that water leaked into the turbine electro-hydraulic control (EHC) oil system and began a Unit 2 shutdown at 12:55 a.m. on September 29, 1986. Tne
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turbine EHC oil system problems started on September 28, 1986, when the standby EHC pump auto started on low pressure and a higher than normal level was discovered in the EHC oil tank. Unit 2 was manually scrammed by procedure GP-3 at 2:19 a.m. on September 29, 1986, from 25% power. Reactor c level dropped to -17 inches and Group II and III primary containment isolations occurred. An ENS call was mad The inspector reviewed the control room logs and indications, and discussed the event with licensed operators and engineers. The inspector examined portions of the EHC system and several " milky" EHC oil samples. The licensee drained the EHC oil system and replaced the oil several times to lower the moisture content. System flushing and servo valve replacements were also performe The EHC system was declared operable and the unit restarted on October 9, 1986. The inspector attended NRB meeting
- 193 which discussed this even Within the scope of the review of the Unit 2 shutdown and EHC system troubleshooting, no violations were note < , ,,-- - - - ,
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4. Unit 3 Auto Scram on October 7, 1986 Unit 3 auto scrammed from 77% power on low reactor water level at 6:22 a.m. on October 7, 1986. Power was reduced on October 6,1986, to repack one condensate pump and leak test condenser water boxes. Three reactor feed pumps (RFP)
were operating in 3-element automatic mode. The B RFP flow indicated full scale high, resulting in a check valve
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slams and a decrease in A and C RFP flow. Reactor level began _to decrease and at +17 inches (normal level is +23)
a reactor recirculation pump runback occurred. The RFP check valves continued to slam. The reactor operator took manual control of the 8 RFP and tripped it. The check valve slamming stopped, however reactor water level continued to decrease to +4 inches, and a low level scram and group II/III primary containment isolations occurred. The level shrink on the scram and low feed flow resulted in reactor water level dropping to an indicated level of -50 inches. HPCI and RCIC systems auto started, and the recirculation pumps tripped (ATWS trip) at -48 inches. (Top of active fuel is -178 inches.) The A and C RFPs, HPCI, and RCIC recovered level to norma Reactor pressure was maintained by the EHC system. The operators secured HPCI and RCIC, and restarted the 3A recirculation pump. The operators trans-ferred the #3 and #4 buses (non vital) to off-site powe The inspector reported to the Control Room at 7:15 a.m. on October 7, 1986. The inspector noted that the reactor was in a hot shutdown condition (all rods inserted) at 900 psig
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and the C RFP was controlling level at +23 inches. The inspector reviewed the following: (1) control room chart recorders and traces; (2) the completed GP-18, Scram Review
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Procedure; (3) the draft Upset and Event Reports; (4) the computer post trip log and sequence of events log, and (5) Control Room operator logs; and, discussed the scram
, with licensed operators and engineers. The inspector also attended NRB meeting #193 which discussed this scra Licensee troubleshooting of the RFPs and the feedwater level control system (FWLCS) determined that the B RFP feed flow temperature compensating component (TE-3-6-54B) was faulty. This faulty temperature element caused an indicated false high feed flow which then caused the FWLCS to runback all RFPs. The RFP runback resulted in a low reactor water level scram. The temperature element and compensating amplifier were replaced and tested satisfactorily, and the unit was restarted on October 8, 198 The licensee's independent safety engineering group (ISEG)
performed a review and prepared an " event report" of this
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event. The inspector reviewed the report and determined it was complete, timely and well writte Recommended corrective actions include:
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Continue to pursue a modification to the FWLCS (MOD
- 1843) to replace the existing system with a fault tolerant syste Complete modifications (MOD #1721) to relocate the RFP minimum flow valves (NRC IFI 277/86-07-02) during each unit's 1987 refueling outages.
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Revise procedure OT-100, " Reactor Low Level" and OT-110, " Reactor High Level" to include steps to place FWLCS in single element control when feed and/or steam flow indications are either upscale or downscale (i.e., faulty indications).
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Review the event in licensed operator requalification trainin The inspector will follow the corrective action Within the scope of the review of the Unit 3 scram, no violations were note .2.3 E-1 Diesel Generator Problems The licensee notified the NRC of problems associated with the E-1 emergency diesel generator (DG) during the annual maintenance outage on October 1, 1986. The DG is a Colt Industries Fairbanks-Morse Model No. 38TD8-1/8, and the
generator is manufactured by Louis Allis. The reported problem was the generator roller bearing insulation break-down, which could lead to voltages being induced in the
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bearing assembly. The induced voltage could cause sub-sequent current flow and potential bearing or race damag The licensee located a replacement bearing and performed repairs. The E-1 DG was taken out of service at 8:00 September 27, 1986. Unit 3 was at full power and in a seven day Technical Specification (TS) 3.5.F.1 LC0 action statement, and Unit 2 was shut down to repair the turbine EHC syste The licensee pursued an emergency TS amendment to obtain relief from the seven day TS LCO for Unit 3. The Regional Administrator granted a five day LCO extension on October 3, 1986 by telephone to Mr. John Kemper of PEco. However, the E-1 DG was returned to service on October 4,1986, before the original LCO expired. Unit 2 remained shut down until the EHC system was returned to service and the E-1 DG was operabl _- _ _
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The inspector reviewed the licensee's emergency TS relief submittal and participated in a conference call on October 2, 1986. The licensee completed repairs and testing of the E-1 DG prior to the TS 3.5.F.1 LCO seven day action statement. The E-1 DG was declared operable on October 4, 198 No violations were note .2.4 Unit 2 Auto Scram on October 13, 1986 Unit 2 auto scrammed from 70% power on low main condenser vacuum at 1:55 a.m. on October 13, 1986. The unit was at reduced power to repair the 2B condensate pump which had failed on October 10, 1986, apparently due to a failure of the pump thrust bearing. The cause of the low vacuum scram was due to air inleakage into the main condenser through the 2B condensate pump suction butterfly valve. The licensee found screen and wire mesh apparently from a startup suction line strainer lodged in the valve seat. When maintenance disconnected the pump suction flange, condenser vacuum decreased to 21" Hg (the scram setpoint is 23" Hg). The response to the scram was normal. Reactor water level decreased to -32" and group II/III primary containment isolations occurred. The reactor feed pumps recovered level. The licensee made an ENS call. The 2B condensate pump suction valve was repaired and leak tested satisfac-toril Plans were made to inspect the other five condensate suction lines and valves when the units are shut down. The unit was restarted, and at 8:43 p.m. on October 13, 1986, the reactor was critica On October 14, 1986, the inspector reviewed the control room logs, instrument chart traces, the computer post trip and sequence of events logs, anc discussed the scram with the on-shift licensed operator The inspector reviewed the draft Upset Report and the completed GP-18, Scram Review Procedure and also attended NRB meeting #193 which reviewed the scram. No violations were r.ote .2.5 Unit 3 Shutdown on October 30, 1986 Due to Resin Injection Unit 3 was manually scrammed at 12:32 p.m., on October 30, 1986, from 37% power due to high reactor water conductivit l The high conductivity was caused by a resin injection which occurred when the 3E condensate demineralizer was placed in'
s,rvice. A high main steam line radiation alarm resulted in the licensee reducing reactor power from 100% to 37%. When
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a chemistry sample indicated that the reactor water conduc-tivity was 40 micromhos/cm and pH was 4.0, the unit was manually scrammed. Technical Specificaticn 3.6.B.3 limit conductivity to under 10 micrombos/cm. Because the E-4 diesel generator was out of service for its annual maintenance, Unit 3 was not restarted until November 4, 1986. The licensee made an ENS call on October 30, 1986, and notified the NRC resident's office.
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The resin injection was similar to the Unit 3 3H condensate demineralizer occurrence on September 14, 1986. That event was reviewed in NRC Inspection 277/86-16; 278/86-17 and documented in LER 3-86-19 (see detail 6.2.2). The inspector discussec these two events with licensed operators and licensee engineers. The licensee is replacing the conden-sate demineralizers elements with a new nylon element because tne original elements can no longer be obtained. Both 3E and 3H, as well as seven other of the 20 total demineralizers, have been re-elemented. The apparent cause of the resin injection was some resin being trapped in the dead leg outlet piping or in the demineralizer plenum during the pre-coat cycl Subsequently, when the demineralizer was placed
"on line", resin is injected into the condensate system and into the reactor vassel. The licensee is modifying the post element changeout inspections and procedures to ensure that no resin is available for injection into the vesse The inspector will continue to follow licensee activities in this area. The LER and final licensee report will be reviewed in a future inspectio Within the scope of the review of the manual scram and licensee followup investigation, no violations were note .2.6 Unit 2 Runback on November 3, 1986 At 9:49 p.m., on November 3, 1986, with Unit 2 at 100%
power, EHC and recirculation pump runbacks occurre The apparent cause of the runbacks were power fluctuations in the static inverter (20D37) uninterruptible power supply panel 20Y50. Panel 20Y50 (120 volt AC) supplies power to the EHC system and recirculation system runtacks. The EHC load set runback closes the turbine control valves and the recirculation pump runback decreases speed cf the motor generator set. Similar runbacks occurred or Unit 3 on February 9,1984, and July 5,1986. These events were reviewed in NRC Inspections 277/84-03; 278/E4-03 and 277/86-13; 278/86-14, respectively. The 1984 event resulted in a scram (LER 3-84-2).
Licensee response to the Unit 2 November 3, 1986, EHC and recirculation runb3cks included manually running back
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recirculation pump speed to obtain 60% reactor power. The EHC runback resulted in all nine bypass valves opening and reactor pressure increased from 980 to 1003 psig (scram setpoint is 1055 psig). The EHC runback was terminated and reactor pressure was returned to normal by the EHC syste The inspector reviewed this event on November 4, 1986, during the morning control room tour. Operator logs and control room chart traces were reviewed. The event was also discussed with licensed operators and licensee engineers. The licensee determined that the apparent cause of the static inverter fluctuations was running the E-4 diesel generator in parallel to the E-42 bus. The E-42 bus supplies the motor control center that feeds the 20 battery charger which supplies the 250 VDC supply to the static inverter. Long term corrective action includes implemen-tation of MOD #1474 to remove the EHC runback coincident with recirculation runback. The EHC runback tends to coun-teract the recirculation runback resulting in the opening of the turbine bypass valves. When all the bypass valves are opened, the net effect is to increase reactor pressur MOD #1474 is scheduled for the 1987 refueling outages for each unit. The inspector will review this in a future inspectio The inspector concluded that operator response to this
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transient was timely and in acco-dance with procedure No violations were note .2.7 Unit 3 Auto Scram on November 4, 1986 Unit 3 auto scrammed during startup from 5% power at 8:26 p.m., on November 4, 1986. The unit was in the startup mode at 480 psig reactor pressure ar.d turbine shell warming was in progress. The #2 turbine stop valve (TSV) was throttled to warm and pressurize the turbine, and the other TSVs were closed. The TSV closure scram was bypassed as first stage pressure was less than 220 psig (indication that reactor power is less than 30%). An apparent increase in first stage pressure (indication of PI-3004 in the control room at 145 psig) with the indicator about 40 psig lower than actual pressure combined with the TSV scram bypass pressure switches (PS-3-5-14A thru D) being set conser-vatively low at 180 psig resulted in auto scram signals to channels A and The licensee confirmed this pressure rise by noting the rod sequence control system (RSCS) back lights extinguished and an increase in indication of turbine steam flow on recorder FR-6-97. Both of these indications ,
are derived from turbine first stage pressure: RSCS bypass
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from PS-250 A and B; and, FR-6-97 from pressure transmitter PT-6-5 Thus, the RPS scram logic caused a full automatic
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scram for channels A and The scram response was norma The licensee entered procedure T-100, "S:: ram". The on-shift personnel informed the senior resident inspector and made an ENS call at 9:20 p.m. The licensee performed an investigation, completed GP-18, " Scram Review Procedure";
drafted a preliminary Upset Report; and convened a PORC meeting at 8:45 a.m. on November 5, 1986. The inspector reviewed GP-18, the Upset Report and attended the PORC meeting. The inspector attended NRB meeting #193 which discussed this scram. The inspector reviewed the RPS electrical schematic MI-S-54, the RPS block diagram, P&ID
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M-303, and control room logs and chart traces; and, discussed the event with the on-shift operators and licensee engineer ,
The inspector determined that the licensee root cause
- analysis was complete. The inspector noted that the PORC meeting was in accordance with procedure A-4, "PORC" and Technical Specification section 6. PORC members demonstrated a g
- od questioning approach to the scram and an excellent perspective of nuclear safety. The inspector also reviewed the implementing procedures for turbine shell warming, GP-2 and S.6.3. ; Licensee corrective actions prior to unit restart included:
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PORC review and approval to restart
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Recalibration of PI-3004
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Calibration check of PS-3-5-14A thru D
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Check alarm setpoint for alarm #C708-18 " Turbine Shell Warming Pressure High".
The inspector verified these corrective actions and the unit was restarted on November 5, 198 Within the scope of the review, no violations were note .2.8 Unit 3 Control Rod #10-47 Uncoupling On November 5, 1986, during the reactor startup from hot shutdown following a reactor scram on November 4, 1986, control rod #10-47 indicated uncoupled when.given an overtravel check at position 48. The licensee inserted the rod and disarmed it electrically as required by Technical Specification 3. Rod #10-47 was the second rod withdrawn during the startup. The first rod withdrawn was also
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inserted. The reactor was placed in cold shutdown, refuel mod The licensee contacted GE and the rod was teste Results of the testing indicated the rod was able to be coupled, however it could become uncoupled at higher drive pressures (i.e., 400 psid). Ten other rods were tested with varying drive pressures,.however no uncouplings occurred. Rod #10-47 was changed out two cycles ago and had no history of problem The licensee noted that the rod was scrammed on November 4, 1986, when the reactor was at 480 psig. Thus, a high differential pressure on the scram concurrent with an un-known problem with the control rod, may have resulted in the rod uncoupling. The licensee is pursuing a filter interference problem previously identified by GE SIL #5 The licensee performed a safety evaluation on November 6, 1986. The safety evaluation concluded that operating with control rod #10-47 fully inserted does not affect the Unit 3 cycle 7 rod drop accident analysis. Control rod #10-47 was blocked in the full-in position as recommended by the Nuclear Review Board (NRB) and approved by PORC. A jumper was installed to indicate the rod position as full-out to j
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the RSCS. The licensee restarted Unit 3 at 10:27 p.m. on November 6, 1986, and re-inserted the three control rods that are symmetrical to rod #10-47.
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The inspector reviewed the safety evaluation, attended the NRB meeting #193 on November 6, 1986, verified that rod j #10-47 was blocked full-in and disarmed, reviewed the startup sequence rod withdrawal, checked operability of the RSCS and RWi1 systems, witnessed portions of the startup and discussed this subject with licensee engineers and t
operators. The inspector determined that NRB members demonstrated good questioning techniques and displayed an excellent perspective of nuclear safety during the review of this problem. No violations were noted. The cause of the control rod #10-47 uncoupling is unresolved pending further investigatio (278/86-20-01)
4.3 Logs and Records
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The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety, correct equipment and lock-out status, jumper log validity, conformance to Limiting Conditions for Operations, and proper reporting. The following logs and records.were reviewed: Shift Supervision Log, Reactor Engineering Logs, Unit 2 Reactor Operator's Log, Unit 3 Reactor Operator's Log, Control Operator Log Book and STA Log Book, Night Orders, Radiation Work Permits, Locked Valve Log, Maintenance
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- 16 Request Forms, Temporary Circuit Modification Log, and Ignition Source Control Checklists. Control Room logs were compared against Administrative Procedure A-7, Shift Operations. Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site management constituted evidence of licensee review. No unacceptable conditions were identifie .4 Engineered Safeguards Features (ESF) System Walkdown The inspector performed a detailed walkdown of portions of the Reactor Core Isolation Cooling (RCIC) systems in order to independently verify the operability of the Unit 2 and 3 system The RCIC system walkdown included verification of the following item Inspection of system equipment condition Confirmation that the system check-off-list (COL) and operating procedures are consistent with plant drawing Verification that system valves, breakers, and switches are properly aligne Verification that instrumentation is properly valved in and operabl Verification that valves are locked, if require Verification that control room switches, indications and controls are satisfactor Verification that surveillance test procedures properly implement the Technical Specifications surveillance requirements.
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No unacceptable conditions were note .5 General Electric Type AK-F-2-25 Breakers and Anticipated Transient Without Scram (ATWS) Recirculation Pump Trip (RPT) System Several failures of GE-AK-F-2-25 breakers at another plant raised concerns over the reliability of these breakers. NRC Region I temporary inspection instruction No. RI-86-02 provides guidance for inspection of GE-AK-2-25 breakers and the breakers used for the ATWS RPT function. The following section documents the inspection required by RI-86-02. Resident inspectors and regional specialists performed this inspection. Attachment 2 provides a listing of documents reviewed.
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4. GE AK-F-2-25 Breaker Usage There are eight GE-AK-F-2-25 breakers at Peach Botto Six are in use and two are held for spares. None of the applications of this breaker are safety relate The breakers are used as follows:
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Recirculation pump motor generator (M/G) set field breaker (four breakers - two each unit)
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Main generator exciter field breakers (two breakers -
one each unit).
Preventive maintenance of these breakers is scheduled every three years. In 1985 all eight breakers were sent to General Electric for preventive maintenance. The breakers were serviced by GE and returned to Peach Botto Philadelphia Electric Company received no documented information on the work by GE. There have not been any )
recorded failures of these breakers since serviced by G ! Review of the computerized history files indicates no failures. These computer files have historical data from January 1984 to the present tim . ATWS RPT Design and Recirculation Pump Trip Breakers 4.5. ATWS RPT Design
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The ATWS RPT at Peach Bottom Units 2 and 3 is accomplished using a "one-out-of-two" logic for low-low reactor water level or high reactor pressure for each recirculation pump. The trip from each logic is applied to a single trip coil of the supply breaker for the recirculation pump M/G set drive motor. Two redundant reactor vessel water level sensors (LIS 57A,8 and LIS 58A,B) and two reactor pressure sensors (PS 102A thru D) are used to provide the required signal Peach Bottom technical specification table 3. specifies the reactor high pressure signal as less than or equal to 1120 psig and the reactor water level signal as greater than -48 inche Either of these trip signals will activate a relay and complete the trip circuit. The ATWS RPT signals trip the 13.8 KV circuit breaker which supplies power to the recirculation pump M/G set drive motor. The reactor water level and pressure switches are different from those used in the reactor protection syste These sensors are environmentally qualified and listed on the Peach Bottom Q list. The logic and control for the
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1 ATWS RPT can be tested on line; however, the breakers are tested when the reactor is shutdow .5. GE Magne-Blast Circuit Breaker (1200 amp)
ATWS RPT signals trip the 13.8 KV circuit breaker which supplies power to the recirculation pump M/G set drive motor. Peach Bottom uses the GE Magne-Blast circuit breaker rated at 1200 amperes for this application. The preventive maintenance program schedules servicing at five year interval The breakers are sent to Power Distribution Company located in Norfolk, Virginia for PM servic Review of maintenance history from January 1984 to the present time did not reveal any significant problems with the breakers. GE
, Magne-Blast Circuit Breakers are used in a number of locations at Peach Bottom. When a problem
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occurs with a breaker, the breaker is replaced i with an operable one. Therefore, the 13.8 KV breakers in the recirculation pump M/G set drive motor circuit are not devoted solely to that application. There has been no failure of the breaker to operate when called upon by the ATWS RPT logic.
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The following tests apply to the ATWS RPT system:
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ST 2.1.12 A-D, " Functional Test / COL Check of PS-2-2-3-102A-D", required by Technical Specification every refueling cycle to verify the operability and setpoint of the pressure switches.
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ST 2.4.02 A,C, " Calibration Check of LIS-2-2-3-57A, B", and ST 2.4.03 A,C,
" Calibration Check of LIS-2-2-3-58A, B,"
required by Technical Specification once every operating cycle to verify the operability and setpoint of the level
, indicating switche ST 13.1 Recirculation Pump Trip Logic System Functional Test required by Technical Specification every refueling cycle to test the RPT logi ,
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RT 4.3 Biannual Tabulation of 13 KV Breaker Operation. This procedure documents breaker operation to allow planning of maintenanc The inspector reviewed a sampling of the tests performed on the ATWS-RPT system. No problems were identified. These tests are listed in Attachment 2 with other documents reviewe . Conclusions Based upon this inspection, no problems were identified with the ATWS RPT breakers or the GE-AK-F-2-25 breakers at Peach Bottom. The licensee has adequate corrective and preventive maintenance programs in place for the breaker Testing of breakers and control logic is satisfactor The inspector had no further question No violations were note . IE Circulars Which Require No Response An NRC IE Circular was previously used to transmit.information to licensees or permit holders when the information is of safety, safeguards or environmental interest but replies from the licensees are not necessary for NRC to assess the significance of the matter. Although the Circular
, does not involve a specific response to the NRC, it contains recommended actions to the licensee. NRC inspection follosup for Circulars involves verification that the licensee received the Circular, reviewed it, and took appropriate corrective actions. NRC Inspection 277/83-37; 278/83-35 reviewed and closed additional Circular For the remaining open Circulars, the inspector verified that the licensee has an effective method for reviewing circulars and assigning followup responsibilities. Circular eview is accomplished within the purview of PORC. The Station Manager garforms the initial review and assigns responsibilitie These are documented by the station compliance group and reviewed by PORC. An initial discussion is conducted in PORC if requested by any PORC member. Response actions are reviewed for acceptability by POR Long-term actions are followed via a PORC Open Items List. Although the review of Circulars by PORC is not specified by either Technical Specifications or licensee procedures, it is included in a standard PORC agenda. Each PORC discussion of a Circular is listed in a PORC index, which includes meeting number and specific paragraph references for auditability.
, For the following open Circulars, the inspector reviewed PORC minutes,
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procedures, or other correspondence to ver.; that appropriate
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20 i evaluations, inspections, or other corrective actions had been taken or Circular N Subject Licensee Action 80-14 Contamination of Check valves added and Demineralized Water letter sent to remind individuals not to drint demineralized water 81-01 Pushbutton Switch Honeywell series 2 Design Problems pushbutton switches not used at Peach Bottom
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81-05 Pipe Support Rod End Recommendations Bushings implemented in maintenance procedure M-6 Control of Recommendations Contaminated Materials implemented in
procedure HP0/CO-100 No unacceptable conditions were identified and the above NRC IE Circulars are considered close '
6. Review of Licensee Event Reports (LERs)
6.1 LER Review The inspector reviewed LERs submitted to the NRC to verify that the details were clearly reported, including the accuracy of the description and corrective action adequacy. The inspector determined whether further information was required, whether generic implications were indicated, and whether the event-warranted on-site followup. The following LER's were reviewed:
LER N LER Date Event Date Subject
- 2-86-18 Reactor water level transmitter out of service September 25, 1986 August 26, 1986
- 3-86-19 Unit 3 shutdown by manual scram due to resin October 16, 1986 injection September 14, 1986 !
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- 3-86-20 Unit 3 auto scram due to FWLCS failure October 27, 1986 October 7, 1986 6.2 LER On-Site Followup For LERs selected for on-site followup and review (denoted by asterisks above), the inspector verified that appropriate corrective
- action was taken or responsibility assigned and that continued operations of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicabiitty to other site systems and components were also reviewe . LER 2-86-18 concerns an iroperable reactor level transmitter, LT-2-2-3-728, noted during a Unit 2'startup on August 26,
-1986, at 4:00 p.m. The licensee noted that the reactor level indication for LI-85B (common tap with LT-72B) was reading abnormally high. Licensee investigat 1 determined that the instrument root valves for LT-728 were closed. At 6:00 p.m.,
the licensee reopened the root valves and returned the LT-72B to service. The cause of closed root valves appears to be improper return to service when the level transmitter was calibrated by I&C technicians on August 11, 1986, in accordance with ST-2.4.04B. The inspecto reviewed the core standby cooling system (CSCS) electrical schematics to determine the effect on CSCS logic. There are four redundant reactor water level transmitters which provide inputs to the CSCS logic.- The LT-72B device provides one logic inpu The inspector determined that the CSCS remained in an
operable status with LT-72B out of service. The inspector discussed this LER with licensee engineers, operators, and I&C technicians. The inspector verified licensee corrective actions. The inspector had no further questions at this tim . LER 3-86-19 concerns a Unit 3 shutdown effected by a manual scram on September 14, 1986. The shutdown was necessary to reduce MSL high radiation caused by a resin injection into the reactor vessel when the 3H condensate filter demineralizer was placed in service. The resin injection event was reviewed in NRC Inspection 277/86-16; 278/86-1 The specific cause of the resin injection could not be identified by the licensee. A similar event occurred when the 3E demineralizer was placed in service (see detail 4.2.5). There were no inadequacies noted relative to this LE . ,
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6. LER 3-86-20 concerns a Unit 3 automatic scram on October 7,1986, due low reactor water level, and the event is reviewed in detail 4.2.2 of this report. There were no inadequacies noted relative to this LE . Surveillance Testing The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met. The following test was observe ST 7.6.1.a. Quantitative Analysis of Gamma Emitters in Off-Gas, Revision 5, performed on Unit 3 on October 1, 198 In addition, a review of the tests listed in Attachment 2 and the following completed surveillance tests was performed:
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ST 7.6.4.a, Off-Gas Radiation Monitor Calibration With a Known Radioactive Source, Rev 0, performed on Unit 2 on 5/1/85 and on Unit 3 on 11/1/8 ST 7.6.1.a, Quantitative Analysis of Gamma Emitters in Off-Gas, Re , performed on Unit 2 (3/9/84 and 2/17/84) and on Unit 3 (6/27/85 and 7/3/85).
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ST 14.4, Response Time Test of Reactor Low Level Scram Channels, Rev
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8, performed on Unit 2 (6/2/85) and on Unit 3 (11/25/85).
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ST 14.11, Response Time Test of Main Steam Line High Radiation Trip
, Channels, Rev 7, performed on Unit 2 (6/2/85) and on Unit 3 l (11/26/85).
- No inadequacies were identified.
! 8. Maintenance
For the following maintenance activity the inspector spot-checked administrative controls, reviewed documentation, r.nd observed portions of
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Maintenance 3 Procedure /
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Document Equipment Date Observed M5 E-1 Diesel Generator October 2, 1986 Administrative controls checked included maintenance request forms (MRFs),
blocking permits, fire watches and ignition source controls, item handling
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- reports, QC involvement, plant conditions, TS LCOs, equipment turnover information, and post maintenance testing. Documents reviewed included
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i-maintenance procedures, material certifications RUPs, MRFs, and receipt inspection ; No violations were noted. Additional maintenance activities reviewed are
! discussed in detail 4.5 of this repor . Radiation Protection
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During the report period, the inspector examined work in progress in both i units, including health physics (HP) procedures and controls, dosimetry '
and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instruments j use, and handling of potentially contaminated equipment and material !
The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation doors was verified to be locked as required. Compliance with RWP requirements was verified during each tour. RWP line entries were reviewed to verify that personnel had provided the required information and people working in RWP areas were
observed to be meeting the applicable requirements. No unacceptable !
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conditions were identifie During this report period a number of workers were finding low levels of contamination on their clothes when using the Eberline Model PCM-1 or
- PCM-1A Contamination Monitor to frisk. The contamination was primarily ,
j due to small leaks in the Unit 3 high pressure turbine steam inlet pipin The licensee has been working at locating and stopping small steam leaks i during this report period. On October 20, 1986, a worker at Peach Bottom j
asked the inspector about internal radiation exposures resulting from the
- steam leaks. He was concerned because the problem existed.for weeks. The inspector explained maximum permissible concentration (MPC) values and the
- licensee's practice of taking protective action before these values are reached. The inspector irdicated he would check the airborne radiation
data and would have additional information the next day. The inspector i determined that the Unit 3 turbine building 165 foot elevation airborne i
radiation levels ranged from about 10E-9 to 10E-11 uci/cc during the period of September - October 1986. Comparison of radionuclide activity with MPC
- values indicated that concentrations were very small fractions of MPC's.
l However, it was noted that Cs-138 was not compared to its MPC value in the licensee's calculation. The inspector independently checked the ratio of
CS-138 to its MPC and found the fraction much les's than one. This issue l was discussed with the licensee, who indicated the calculatioas would be
changed to include the pruper MPC value for Cs-138. The inspector will
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review the changes when they are made. The inspector concluded that the airborne radioactivity levels were low, presented no undue hazard, and the '
licensee was taking appropriate actions.
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10. Physical Security 10.1 Routine Observations The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: operations of the CAS and SAS, checks of vehicles on-site to verify proper control, observation of protected area access -
control and badging procedures on each shift, inspection of physical i barriers, checks on control of vital area access and escort procedures. No inadequacies were identifie .2 Standby Liquid Control System (Unit 3) Breaker Compartment -
With Unit 3 at full power and Unit 2.in cold shutdown at 4:05 p.m.,
on October 17, 1986, during a control room panel walkdown, the licensee noted that the 3B standby liquid control system (SLCS)
pump's green indicating light was off. Inspection of the 3B SLCS pump motor control center (MCC) breaker compartment revealed that the top vertically mounted terminal strip was removed and placed on the side of the breaker compartment. The terminal strip is a knife type connector inside the breaker compartment and it provides only control room indication for 3B SLCS pump (green and red lights). The licensee determined that the 3B SLCS pump remained operable. The licensee returned the terminal strip to normal; and, performed a system check off list (COL) for the SLCS. Also, the licensee performed ST 6.1, "SLCS Functional Test" on both Units 2 and All operability teste were completed satisfactorily. The licensee informed the resident inspector at 6:00 p.m., and made an ENS call
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at 6:50 p.m. on October 17, 1986. The licensee performed a walkdown of all indications in the control room and no other deficiencies were noted. The licensee also performed a walkdown of the RPS and control rod drive hydraulic control units, and no abnormalities were noted.
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The senior resident inspector and a regional security inspector res-ponded to the site on Saturday, October 18, 1986. The licensee formed an on-site security team to investigate the circumstances of the even The inspector verified that SLCS operability was not affected by reviewing electrical schematic drawings. Discussions were held with
- licensee operators, engineers, and security force personnel. The inspector reviewed the completed COLs and ST 6.1 result No unacceptable conditions were note The licensee reported the security event as a possible tampering incident on October 29, 1986. The inspector reviewed the written report. The licensee has not determined who accessed the breaker compartment and for what reason, the removal of the SLCS pump 3B breaker compartment terminal strip remains unresolved. (UNR 278/86-20-02).
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2S 10.3 Security Protected Area Walkdown On October 16, 1986, the inspector performed an inspection of the protected area boundary. At the same time, discussions were held with the Peach Bottom Security Specialist about the security progra Items examined during the inspection included:
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Condition of physical' barriers
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Security detection devices
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Conditions of isolation zones
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Vehicles and material in the protected area and on-site
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Warehouse security features
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Security patrols
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New security building
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Implementation of security procedure The inspector observed CAS operations and questioned the CAS operator. Other security personnel were questioned about their duties and training. Security personnel were knowledgeable of their duties. A recently initiated licensee quality control inspection of security activities was observed in progres No unacceptable conditions were note . Unresolved Items Unresolved items are item's about which more information is required to ascertain whether they are acceptable violations or deviations. Unresolved items are discussed in detail *.2.8 and 1 . Management Meetings 12.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Superin-tendent of Operations at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspectio No proprietary information is included in this report.
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12.2 Attendance at Management Meetings Conducted by Region Based Inspectors Inspection Reporting-Date Subject Report N Inspector 10/10/86 Annual Emergency 277/86-15 Gordon Exercise 278/86-16 '
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10/24/86 Radwaste 277/86-21 Bicehouse Transportation 278/86-22 10/16/86 Fire Protection N/A Krasopoulos Management Meeting
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11/7/86 Environmental 277/86-23 Jang Monitoring 278/86-24 12.3 NRC Region 1/PECo Management Meeting on October 3, 1986 On October 3, 1986, a management meeting was held at NRC Region At this meeting, PECo discussed their " Peach Bottom Enhancement Program (PBEP)". The PBEP was developed in response _to the Jun SALP Report and the Region I Diagnostic Team Inspection Report 277/86-12 and 278/86-13. The PBEP is designed to improve the short and long term safety, reliability, and operating effectiveness at Peach Bottom. Specific goals, objectives, action items and tasks were discussed. A list of meeting attendees is included in Attachment 1 to this inspection repor The inspector will follow the implementation of the PBE i a
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ATTACHMENT 1 NRC Region 1/PECo Meeting Attendees On October 3, 1986
, e-a PECo Personnel J. E. Winzenried, Staff Engineer G. M. Leitch, Superintendent, Nuclear Generation
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R. S. Fleischmann, Manager, PBAPS D. C. Smith, Superintendent, Operations, PBAPS -
M. J. Cooney, Manager Nuclear Production W. M. Alden, Engineer in Charge, Licensing D. P. Helker, Engineer, Licensing B. L. Clark, Sr Engineer, Special Projects Nuclear J. B. Richard, Consultant J. B. Cotton, Superintendent, Plant Operations, PBAPS NRC Personnel T. F. Dragoun, Senior Radiation Specialist P. H. Bissett, Reactor Engineer C. J. Cowgill, Acting Chief, Emergency Preparedness & Radiation Protection Branch R. J. Bailey, Physical Security Inspector
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P. W. Eselgroth, Projects Section Chief 2A
{ T. P. Johnson, Senior Resident Inspector, PBAPS -
l S. D. Ebneter, Director, Division Reactor Safety i
S. J. Collins, Deputy Director, Division of Reactor Projects R. M. Gallo, Chief, Projects Branch No. 2 W. V. Johnston, Deputy Director, Division of Reactor Safety i
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ATTACHMENT 2 x b g ,
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Drawings: '
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M-351, Rev 24, P&ID Nuclear Boiler '* 5 i ,
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M-352, Rev 21, P&ID Nuclear Boiler Vessel Instruientation
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M-353, Rev 11, P&ID Reactor Recirculation Pump System i --
E-5, Rev 7, Single Line Meter & Reli.y Diagram - 13.8 KV Aux Power System
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E-1, Rev 15, Single Line Diagram Station
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E-171, Rev 25, Sheets 1, 2, & 3 Electrical l Schematic Diagram, Recirc M-G l Set Drive Motor 13.8 KV Circuit Breaker Maintenance Request Forms:
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860108850, U3 Alternator Exciter Field Breaker PM
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860008820, 3A Recirc M-G Field Breaker PM
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860008830, 3B Recirc M-G Field Breaker PM
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Surveillance Tests:
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ST 13.1, " Recirculation Pump Trip Logic System Functional Test", performed on:
Unit 2 Unit 3 August 4, 1980 September 11, 1981 June 18, 1982 August 15, 1983 May 24, 1985 June 27, 1985 November 11, 1985
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ST 2.4.02A, " Calibration Check of LIS 57A", performed on Unit 2 on:
i August 10, 1986 June 21, 1982 March 27, 1980 July 27, 1980 i July 18, 1981 ^
October 4, 1983 April 15, 1985
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ST 2.1.12A, " Functional Test / Calibration Check for PS-2-2-102A", performed
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January 27, 1981
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u 2 Attachment 2 m
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February 23, 1982 -
July 23, 1983 May 18, 1985
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RT 4.3, " Biannual Tabulation of 13 KV Breaker Operation", performed on July 15, 1979
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