ML20212J601

From kanterella
Jump to navigation Jump to search
Annual Operating Rept,Jan-Dec 1986
ML20212J601
Person / Time
Site: Fermi 
Issue date: 12/31/1986
From: Sylvia B
DETROIT EDISON CO.
To:
NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
GP-87-0007, GP-87-7, NUDOCS 8703090065
Download: ML20212J601 (39)
v • d • e


Text

{{#Wiki_filter:- i Fermi 2 Annual Operating Report January 1 - December 31, 1986 ( Detroit Edison Company NRC Docket No. 50-341 Facility Operating License No. NPF-43 1

  • e O

p e +

c. \\o Table of Contents f*A*. 1.0 Introduction 1 2.0 Summary or Operating Experience 1 2.1 Summary of Operations 1 2.2 Summary of Outages and Forced Reductions Greater Than 20 Percent of Full Power 2 2 3 Fuel Performance 3 2.4 Shore Barrier Survey 4 2.5 Safety Relief Valve Challenges 4 2.6 Personnel Monitoring and Exposure 5 27 ECCS Outages 7 2.8 Service Life of Main Steam Bypass Line 19 30 Facility Changes, Tests and Experiments 20 31 Design Changes 20 32 Procedure Changes 32 3 3 Tests and Experiments 35 a,

'/ l Fcral 2 j 1.0 Introduction 4 The Farsi 2 Nuclear Power Plant site is located on the i western shore of Lake Erie in Frenchtown Township, Monroe 4 l County, Michigan. The Nuclear Steam Supply System is a General Electric MR 4, with a pressure-suppression Mark I containment. The unit is rated at 3292 MWt. The plant is owned jointly by the Detroit Edison Company (approminately 90 percent) and the volverine Power Supply Cooperative, l Incorporated (approximately 10 percent). Detroit Edison hp.s reached agreement with Wolverine Power Supply Cooperative i Inc. to purchase the cooperative's remaining ownership interest in Fermi 2 effective January 1, 1990. Detroit ' Edison has exclusive responsibility and control over the -l -{ operation and maintenance of the facility. - rl l ( 2.0 Summary of Operatina Esperience 2.1 Summary of Operations this operations summary covers the period from January l 1, 1986 to December 31, 1986. The plant was shut down l on October 11, 1985 for a scheduled maintenance outage. The outage continued to August 4, 1986. l Primary activities during the outage included I improvements to enhance the reliability of the emergency diesel generators (EDGs), replacing the neutron source within the, reactor and constructing an j intermediate switchyard. ) Startup testing resumed upon authorisation of plant restart in a letter from James Reppler, NRC Regional Administrator dated September 12, 1986. This i. authorisation also lifted the 55 pawer restriction and f permitted the plant to operate not in excess of 20% of - rated thermal power. The first time the plant operated i above 55 power was on September 16, 1986. Initisi Electricity was generated on September 21, 1986. 4 i j On November 7, 1986, the plant was shut down to repair l the probles of excessive air in-leakage into the condenser. The outage scope was subsequently espanded I to include installation of new relief valves to prevent l future overpressurization of the condensate return i line. The reactor was restarted on December 19, 1986. 1 Test Condition 1 testing of Startup Test Phase 1 continued but, remained incomplete at the end of 1986. i i 1 l 1 e --,~n--,--,~~-~~m n ww. n,wn,.,w,,,a--,--

(, _. 7 Fermi 2 ') h I }l /' 2,2 funnry of Outages aid Forced Reductions Greater 'fhan \\ / j. 20 percent of Full Power 1 January 1 - August 4, scheduled shutdown - 5178.4 houra

i..

The plant uns shut down October 11, 1985 fee a schedc13d maintenance outage. Major i?.c;ta completed during this outage included repair and, toting of the s/ Energer.cy Diesel Generators, modificat;ons to the I Traverring'In-Core Probe nitrogen purg# line, cooling tower modifications, work associated rft!: the south F reartor feed pump and turbine, nasutron source cnangeout, Main Steam Isolation Valve repair, Main , Steam Safety / Relief Valve testing and repair, replacement of the Division I and II 240/120V i ' batteries, Soquence of Events Itecorder modifications and ultrasonic testing on the main steam bypass lines. Auguet s August 7, forced shutdown - 93 6 hours. Management decision to shut down after a fire that occurred in a Motor Control Center. Reported as LER 86-026, transmitted Septamber 5,1986, by NP860484. ' Pursuant to the Plant Emergency Plan, an Alert was declared. August 29, forced snutdown - 26 9 hours. I Reactor trip on high Reactor Pra:sure Vessel (RPV) pressure trarJient. Reported as LER 86-031, transmitted September 25, 1986 by NP860525. f, September September 3. forced shutdown - 81.5 hours. Shutdown required by Technical Specifications to repair an isolatio:t val'fe. Reported as LER 86-027, transertied Octoter 2, 1986 by NP860535. i September 23, forced shutdown - 217.4 hours, Stutdown to repair condenser tube leaks to maintain proper reactor aoolant chemistry. October October 1, forced shutdown - 67 3 hours. i Contfnuation of outage that began September 23 ',,j \\ 2 a

Fi r::1 2 october 5, forced shutdown - 44.4 hours. While starting the main turbine generator, the Gland Sealing Steam pressure regulator malfunctioned. Reported as LER 86-035, transmitted November 3, 1986 by NF860588. ' October 9, forced shutdown - 103 6 hours. Shutdown to investigate the loss of 120 Vac instrument power. Reported as L3R 86-036 transmitted November 7, 1986 by NP860603 November November 7, forced shutdown - 560.9 nours. Shutdown to repair the cause of excessive air in - leakage into the condenser. Outage acope was expanded to include installation of new relief valves to prevent future overpressurization of the condensate return 1 line. On November 17, overpressurization of this line caused an expansion joint to rupture and danaged a penetration in the Condensate Storage Tank. Reported as LER 86-045 transmitted January 12, 1987 by NP870025. Dece_mber December 1, forced shutdown - 435.1 hours. Continuation of outage that began November 7 2,3 Fuel "irfo? nance The initial startup of the year occurred on August 4, 1986 following a ten-month outage. Since then, the =( reactor has achieved criticality ten times and has generated appro:imately 72 MWD of thermal energy. De current core average exposare is approximately 100 MWD (t). Thermal power has been limited to 5% during Heat Up testing. Autherisation to operate not in excess of 20% of rated thermal power was received on September 12, 1986, h e plant entered Test condition 1 (TC-1) on Septeober 16, 1986. The daily average thermal power exceeded 5% on only 19 days. The 20% limit was exceeded once during a brief pressure transient. Maximum power was estimated to be 225 3

w-1..--e-rr

,-,v ---...-m. ...---,-_--,-mm. ., - - -. - -. -,.. ~

l h. t l l Fermi 2 During the outage it became necessary to replace the neutron sources. The source changeout occurred between May 9 and 12. Because of the core alterations made during replacement of the nuetron source and the long outage, it was determined that the Shutdown Margin, Reactivity Anomaly, and Scram Time tests should be performed again. The Shutdown Margin and Reactivity l Anomaly tests were performed and met the technical specification requirements. Ninety-eight of the 185 control rods were scram time tested. The remainder will be tested prior to exceeding 40% power. Nater chemistry was a recurring problem since the August startup. Conductivity was out-of-spec 106 hours. Technical specifications allow 336 hours out-of-spec in a twelve sonth period. Conductivity l will continue to be monitored closely. No fuel failure has been indicated by the offgas samples. ~ 2.4 Shore Barrier Survey A survey of the Fermi 2 shore barrier was completed on August 14, 1986 per procedure 43 000.01 " Shore Barrier Surveillance" and as required by Technical Specification 3 7 3 The results of the survey indicated no damage, significant movement or deterioretion of the barrier. Forty four (44) of the forty seven (47) survey point elevations were within the tolerance specified in Technical Specification Table 3 7 3-1. The remaining three (3) survey point elevations were obstructed (underwater) and optical and electronic equipment inspection was not possible. Visual inspection of the 3 obstructed survey point elevations indicated no degradation in the shore l.o barrier. Civil Engineering drawings 6C721-11 through 49 were revised to incorporate the survey data. No unusual incitients occurred in 1986 that would have required additional surveillances. 25 Safety Relief Valve challenges There were no Safety Relief Valve challenges during 1986. I N

Fc r::1 2 2.6 Personnel Monitoring and Exposure Pursuant to 10CFR 20.407(a)(2), a tabulation of the number of individuals for whom monitoring was provided is shown in Table 2.6-1. Table 2.6-2 provides a breakdown of radiation exposure by work and job function as required by Technical Specification 6.9 1.5(a). Table 2.6-1 Statistical Suasary Report of the Number of Individuals for Whos Personnel Monitoring was Provided. For the Period January 1, 1986 to December 31, 1986 NLMBE:R OF DOIVIDUAIS ESTIMATED WHOE BCDY EXPOSURE RANGE IN EACH RANGE (RDE) 3068 NO MEASURABLE EXPOSURE 151 EXPOSURE < .10 1 .10 to .25 0 .25 to .50 0 .50 to .75 0 .75 to 1.00 0 1.00 to 2.00 0 2.00 to 3.00 0 3.00 to 4.00 1 0 4.00 to 5.00 0 5.00 to 6.00 0 6.00 to 7.00 0 7.00 to 8.00 0 8.00 to 9.00 0 9.00 to 10.00 0 10.00 to 11.00 0 11.00 to 12.00 0 12.00 and Over 5 - + - - -, ~-

e Tablo 2.6-2 Farai 2 Annual Exposure Report By Function For the Period of: 01/01/86 to 12/31/86 Amber of Personnel >100mhen Total nue-SEN Stetten Stility Contractors Stetten Stility Contractors Jer.U.dI M m H a "Is m i Init a l. m i. R m i l e ls m a..l e lt m l e f. B !t h Spector Oper 8 Surveillance maintenance Personnel 0 0 0 0.014 0.000 0.032 Operating Personnel 0 0 0 0.212 0.000 0.012 Neenth Physics Personnel 0 0 0 0.074 0.000 0.075 Segervisory personnel 0 0 0 0.200 0.000 0.153 Engineersag personnel 0 0 0 0.130 0.015 0.I40 Gewtime Maintenance-Neintenance Personnel 0 0 0 0.53 0.002 0.296 Deratine Personne! 0 0 0 0.022 0.000 0.025 Neelth Physics Personnel 0 0 0 0.000 0.000 0.000 Segervisory personnel 0 0 0 0.000 0.002 0.005 Engineering Personnel 0 0 0 0.013 0.006 0.032 laservice Inspection heintenance Personnel 0 0 0 0.000 0.000 0.000 1 Operating Personnel 0 0 0 0.000 0.000 0.002 NoeIth Phystes Personne1 0 0 0 0.062 0.000 0.000 Supervisory Personnel 0 0 0 0.011 0.000 0.015 Engineersag Personnel 0 0 0 0.000 0.000 0.000 Special Maintenance nenntenance personnel 0 0 0 0.029 0.000 0.070 Operating Personnel 0 0 0 0.015 0.000 0.002 Noelth Physics Personnel 0 0 0 0.017 0.000 0.024 Supervisory Personnel 0 0 0 0.000 0.000 0.016 Engineering Personnel O 0 0 0.011 0.000 0.011 Weste Processing Neintenance Personnel 0 0 0 0.000 0.000 0.00C Operating Personnel 0 0 1 0.000 0.000 0.117 Nealth Physics Personnel 0 0 0 0.011 0.000 0.013 Supervisory Personnel 0 0 0 0.000 0.000 ' O.000 Engineersng Personnel 0 0 0 0.000 0.000 0.000 asfueling heintenance Personnel 0 0 0 0.000 0.001 0.000 Operating Personnel 0 0 0 0.000 0.000 0.000 Neelth Physics Personnel 0 0 0 0.000 0.000 0.000 Supervisory personnel 0 0 0 0.000 0.000 0.000 L gtneering Personnel is 0 0 0.000 0.000 0.000 Totals noir:tenance Personnel 0 0 0 0.IN 0.002 0.406 Operating Personnel 0 0 1 0.249 0.000 0.150 Meelth Physics Personnel 0 0 0 0.104 0.000 0.112 Supervisory Personnel 0 0 0 0.291 0.002 0.109 Engsneering Personnel 0 0 0 0.062 0.021 0.i91

i WWe 101 AL5 0

0 1 0.032 0.025 1.056 6 ,.---,,..,,,-e,,_,_ ..n-g,_. ,,,,,_,.,,,,-,,_--,-y,

Fermi 2 2.7 ECCS Outages Pursuant to Fermi 2 Technical Specification 6.9.1.5.c a summary of ECCS System Outages which occurred between January 1,1986 and December 31, 1986 is provided. The tabulation of total outage hours (Table 2.7-1) includes both forced and planned outages. Equipment failures which would have forced a system outage have been reported as separate outages. ECS Outage Hours January 1, 1986 to December 31, 1986 ECCS System Forced Hours Total Hours t l LPCI Division I 2226.8 3831.7 LPCI Division II 2481.6 5057 7 Core Spray Division I 2110 3077 5 Core Spray Division II 2488.4 3884 HPCI 2299.1 3323 ADS 0 0 Table 2.7-1 ECCS System Outage: Division I & II Low Pressure Coolant Injection i Out of Service from 1615 1-16-86 to 1600 4-15-86 Duration: 2110 hours Forced Outage j Outage Summary Both divisions of RHR were declared inoperable while an evaluation was performed to resolve concerns about concrete embedments for hangers on 1 the RHR system. Initial data indicated that a number of embedded supports in the Reactor Auxiliary Building were potentially l' l. overloaded. Subsequent analyses of the embedded plates using as-built i information, refined hanger loads and refined embedment analysis showed that all of the embedded plates investigated were acceptable (Reference LER 85-082-02 transmitted via NP860096 dated February 28, 1986). This concern did not result in any field modifications. ECCS System Outage: Division I & II Low Pressure Coolant Injection i Out of Service from 1255 7-16-86 to 1445 7-16-86 l Duration: 2 hours Planned Outage Outage Summary l During a plant outage, with the Reactor Pressure Vessel (RPV) head off, corrosion indications were found on the RPV head flange. Both divisions of RHR were taken out of service while repairs were made to the RPV head. l 7

Fs r:li 2 ECCS System Outage: Division I & II Low Pressure Coolant Injection ) Out of Service from 1309 9-3-86 to 1045 9-6-86 Duration: 69.6 hours Planned Outage Outaae Summary i The RHR system was removed from service to inspect cable terminations at LPCI Loop "A" Inboard Injection isolation valve (E11-F015A). 1 During a field inspection it was discovered that external field cable l terminations made in recently replaced valve operators were not made l 'in accordance with Detroit Edison specifications. The cable l l inspection for E11-F015A was completed and the cable was reterminated l prior to returning the system to service. f ECCS System Outgge: Division I Low Pressure Coolant Injection l Out of Service from 1750 1-22-86 to 1700 2-9-86 Duration: 431.2 hours Forced Outage Outage Summary Division I RHR was taken out of service after loss of position indication in-the Control Room for E11-F610A, the bypass valve on the injection line check valve. The cause was determined to be a failed f limit switch which was then replaced. ECCS System Outage: Division I Low Pressure Coolant Injection Out of Service from 1500 1-23-86 to 0830 3-11-86 Duration: 1121.5 hours Planned Outage Outage Summary Division I RHR was taken out of service to perform an inspection of ) RHR pump "C" and to perfora preventive maintenance on RHR pump "A". Maintenance was also performed on the heat exchanger. ECCS System Outage: Division I Low Pressure Coolant Injection l\\ Out of Service from 0150 3-18-86 to 1037 3-18-86 l Duration: 8.8 hours Forced Outage Outage Summary Division I RHR was taken out of service when RNR pump "C" Torus 1 Suction Valve E11-F004C failed to open due to a blown fuse. The fuse was replaced and the valve functioned normally. The cause of the blown fuse could not be determined. l l-I 8 t

= Fcr:1 2 ECCS System Outage: Division I Low Pressure Coolant Injection Out of service from 0500 3-20-86 to 1730 3-24-86 Duration: 68.5 hours Forced Outage Outage Summary Division I RHR was taken out of service when RHR Pump "A" Torus Suction Valve, E11-F004A, would not operate. The cause was determined to be a mechanical problem in the gear box of the valve operator. The mechanical problem was corrected. During this outage the power supply to RHR Pump 'C" Torus Suction Valve, E11-F0040, was found to contain an incorrectly sized fuse. The fuse was replaced with one of the proper size. ECCS System Outaige: Division I Low Pressure Coolant Injection Out of Service from 0045 4-22-86 to 1230 6-20-86 Duration: 1452 3 hours Planned Outage Outage Summary The purpose of this outage was to operationally test the leakage between Division I and II Cross Tie Valve (E11-F010). Also, the Recirculation Valve (E11-F007A) for RHR pumps "A".and "C" required adjustments to the limit / torque switches to ensure the valve would stroke properly under dynamic conditions. The system was returned to service upon completion of these items. ECCS System Outage: Division I Low Pressure Coolant Injection 4 Out of Service from 0430 6-28-86 to 0310 6-30-86 Duration: 45.3 hours Forced Outage Outage Summary The Division I RHR system was declared inoperable when the thermal overload devices on the Division I RHR Injection Valve (E11-F015A) tripped when the valve was stroked in the open direction. The torque switch and limit switches were adjusted and the system was returned to service. ECCS System Outage: Division I Low Pressure Coolant Injection Out of Service from 1130 5-16-86 to 2025 8-16-86 i Duration: 9 hours Planned Outage Outage Summary Division I RHR was removed from service for an inspection of three valves to determine if there were any wiring discrepancies on valve motors. The three de-energized valves were the Inboard Injection Isolation Valve (E11-F015A), the Outboard Injection Isolation Valve (E11-F017A) and the Containment Spray Isolation Valve (E11-F028A). LER 86-025-01 (transmitted via NP860536 dated October 3, 1986) identified a design error which could possibly prevent proper valve closure. 9 ,,mm e.-.w, . x

m-,. -, - - - -

,m.,,mm -.-.m

Fsrai 2 Outage Summary (Cent') The inspection revealed that automatic closure termination of E11-F028A was affected by this design error. Temporary wiring changes were implemented to ensure full valve closure. The inspection verified that closure circuitry,of valves E11-F015A and E11-F017A did not involve this error. Upon completion of the inspection and the temporary modification, the system was returned to service. ECCS System Outage: Divison I Low Pressure Coolant Injection Out of Service from 0600 9-13-86 to 0600 9-16-86 Duration: 72 hours Planned Outage Outage Summary Division I RHR was taken out of service in order to perform preventive maintenance on RHR pumps "A" and "C". Preventive maintenance was also performed on the Division I RHR room cooler. ECCS System Outage: Division I Low Pressure Coolant Injection Out of Service from 1400 12-3-86 to 1330 12-6-86 Duration: 71.5 hours Forced Outage Outage Summary The Division I RHR system was declared inoperable due to an inoperable snubber on the RHR pump discharge piping. The snubber reservoir was found detached from the snubber. Prior to declaring the snubber operable an e'ngineering evaluation was performed and it was concluded that the failure of this snubber had no adverse effect on the piping system or attached components. The snubber was replaced and the system was returned to service. ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 1600 1-22-86 to 1925 2-3-86 Duration: 291.5 hours Forced Outage .i' Outage Summary RHR pump motor "B" was declared inoperable until questions raised by General Electric (the manufacturer of the motor) regardir.g environmental qualification (EQ) of the motor in the Fermi 2 application were answered. In November 1985 RHR pump "B" motor tripped. The damaged motor was shipped to GE for repairs. Anticipating a long delivery, a replacement motor was loaned by TVA's Browns Ferry Plant. Nuclear Engineering evaluated the use of the Browns Ferry motor at Fermi 2 and determined that EQ requirements were met. After resolution of General Electric's concerns, RHR pump motor "B" was declared operable. 10

<+ Farsi 2 ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 1700 2-25-86 to 0020 3-1-86 Duration: 79 3 hours Planned Outage Outage Suasary The Division II RHR heat exchanger was removed from service to change the conductivity cells. The necessary repairs were completed and the heat exchanger was returned to service. ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 0600 4-14-86 to 2200 4-19-86 Duration: 136 hours Planned Outage l Outage Summa g 3 The Division II RHR system was removed from service to perform l preventive maintenance on RHR Pump "D". I ECCS System Outage: Division II Low Pressure Coolant Injection .Out of Service from 0045 4-22-86 to 1300 7-25-86 Duration: 2268 hours Planned Outage l Outage Summary The Division II RHR system was removed from service to perform the following: test of heat exchanger relief valve E11-F029; set limit / torque switches on E11-F007B, RHR Pumps "B" and "D" Minimus Flow valve; repair'E11-F082, Crosstie Header Valve Bypass to Loop "A'; lubricate and test E11-F060B, LPCI Loop "B" Injection Line Manual Isolation Valve; repair Loop "B" flow indicator; modify LPCI Loop Select; repair the indication for E1150-F050B, LPCI Loop "B" Injection Line Testable Check Valve; LLRT of High Drywell Pressure Instruments; and replace Non-ASME position indicating parts in E11-F060B. During this outage, Systen Service Transformer 65 was taken out of service rendering Division II RHR inoperable. ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 0800 8-17-86 to 1800 8-17-86 Duration: 10 hours Planned Outage Outage Summary Division II RHR was removed from service for an inspection of three valves to determine if there were any wiring discrepancies on valve motors. The three de-energized valves were the Inboard Injection l 1 solation Valve (E11-F015B), the Outboard Injection Isolation Valve (E11-F017B) and the Containment Spray Isolation Valve (E11-N 28B). LER 86-025-01 (transmitted via NP860536 dated October 3, 1986) identified a design error which could possibly prevent proper valve i closure. The inspection revealed that automatic closure termination i of E11-F028B was affected by this design error. Temporary wiring l changes were implemented to ensure full valve closure. 11 s .--2. .-.-,,,,_w-.,.,_s,_-_..,_,- ,,_,y,, ,,,,__,,,,.%,,,..p,

Fermi 2 Outage Summary (Cont') j The inspection verified that closure circuitry of valves E11-F015B and E11-F017B did not involve this error. Upon completion of the inspection and the temporary modification, the system was returned to service. ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 0958 8-25-86 to 0313 8-26-86 and from 0846 8-26-86 to 0320 8-27-86 Duration: 35.8 hours Forced Outage Outage Summary The Division II SHR system was taken out of service when it was discovered, while performing channel checks, that the RHR discharge pressure instrument (E11-N656D) was not within specifications. A check of the instrument revealed that all values were within the tolerance. It was suspected that the associated transmitter (E11-N056D) was stuck downscale. The instrument was then returned to service. Subsequently, the RHR discharge pressure instrument (E11-N656D) again began reading downscale. The Division II RHR system was taken out of service and the transmitter (E11-N056D) was replaced. This was reported in LER 86-029 transmitted via NP860513 dated September 22, 1986. ECCS Systea Outage: Division II Low Pressure Coolant Injection l Out of Service from 1845 9-25-86 to 0520 9-29-86 l Duration: 82.6 hours Planned Outage Outage Summary Division II RHR was removed from service to inspect cable terminations at LPCI Loop "B" Inboard Injection Isolation Valve and Containment Spray Isolation Valve (E11-F015B and E11-F028B). During a field i,- inspection it was discovered that external field cable terminations I' ande in recently replaced valve operators were not ande in accordance with Detroit Edison specifications. The cable inspections for E11-F015B and E11-F028B were completed and the cable was reterminated prior to returning the system to service. ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 0600 10-16-86 to 1025.10-18-86 Duration: 41.9 hours Planned Outage Outage Summary The Division II RHR system was removed from service to perform preventive maintenance on RHR Pump "D"; verify the limit / torque switch I settings on E11-F0488, "B" heat exchanger bypass; and perform a wiring inspection on E11-F028B, RHR Loop "B" Containment Spray / Test Isolation valve. l 12

. rJh 4;. s Ferral 2 ECCS System Outage: Division II Low Pressure Coolant Injection Out of Service from 1415 11-21-86 to 0535 12-5-86 Duration: 327.3 hours Forced Outage ,0utage Summary Systen Service Transformer.65 was taken out of service rendering Division II RHR inoperable. During this outage, the position indication switches on LPCI Loop "B" Injection Line Testable Check valve (E11-F050B) were adjusted and the high drywell pressure transmitter (B21-N094F) exceeded its expected time response as specified in the surveillance procedure (44.030.308). However, the overall system response time was within acceptable limits and, therefore, no further action was required. ECCS System Outage: Division II Low Pressure Coolant Injection l Out of Service from 0550 12-18-86 to 1420 12-18-86 Duration: 8.5 hours Forced Outage i Outage Summary Division II of the RHR system was taken out of service when it was discovered while performing channel checks, that the RHR discharge pressure instrument (E11-N656B) was not within specifications. A check of the instrument revealed that the associated transmitter (E11-N065B) was sticking downscale. The transmitter was cycled with process pressure. Readings were taken and found to be satisfactory. I The system was then returned to service. ECCS System Outage: Division I & II Core Spray Out of Service from 1615 1-16-86 to 1600 4-15-86 Duration: 2110 hours Forced Outage j i Outage Summary Both divisions of the Core Spray system were declared inoperable while i an evaluation was performed to resolve conccens about concrete embedments for hangers on the Core Spray systas. Initial data indicated that a number of embedded supports in the Reactor Auxiliary Building were potentially overloaded. Subsequent analyses of the embedded plates using as-built infonation, refined hanger loads and refined embedaent analysis showed that all of the embedded plates investigated were acceptable (Reference LER 85-082-02 transmitted via NP860096 dated February 28, 1986). nis concern did not result in any field modifications. l 13 r-, -'~ -. ,..-~. _,.,n,.n, .wn---,, ]

Farci 2 ECCS Systes Outage: Division I & II Core Spray Out of Service from 1255 7-16-86 to 1445 7-16-86 Duration: 2 hours Planned Outage. Outage Summary During a plant outage, with.the Reactor Pressure Vessel (RPV) head off, corrosion indications were found on the RPV head flange. Both divisions of the Core Spray System were taken out of service while repairs were made to the RPV head. ECCS Systes Outage: Division I Core Spray Out of Service from 1145 2-1-56 to 1000 3-10-86 4 Duration: 886.3 hours Forced Outage r Outage Summary Division I of the Core Spray System was taken out of service after it was discovered that pipe supports on a minimum flow line were loose. The supports were retightened. 'Ihis outage presented an opportunity to perform routine maintenance on Core Spray Pump "A" notor breaker. ECCS System Outage: Division I Core Spray System Out of Service form 1855 5-11-56 to 1030 6-2c-86 Duration: 928.5 hours Planned Outage Outage Susaary The Division I Core Spray system was removed from service to perform local leak rate testing and repairs. A local leak rate test was performed on the Loop "A" Pump Suction Pressure Relief Valve, E21-F032A. A modification to the Division I Logic Relay (E21-K12C) ~ was implemented in order to resolve a problem in the Core Spray system annunciator alara windows. The Loop "A" Suction from Suppression Pool Isolation Valve (E21-F036A) failed it's local leak rate test, was repaired and then successfullly completed the local leak rate test. ECCS System Outage: Division I Core Spray Out of Service from 0400 5-18-86 to 1900 8-18-86 2 Duration: 15 hours Planned Outage Outage Summary The Division I Core Spray was taken out of service to inspect cable i terminations at Loop "A" Inboard Isolation Valve E21-F005A. During a field inspection it was discovered that external field cable terminations made in recently replaced valve operators were not made in accordance with Detroit Edision specifications. The cable inspection for E21-F005A was completed and the cable was reterminated prior to returning the system to service. 14 r-swv ,m v-~e-- -ow,-wr -e--- ,,,,----n w-e---o, --e-- -,---------~----s --~------------------w

. _ = Farci 2 ECCS System Outage: Division I Core Spray Out of Service from 1030 11-25-86 to 0830 11-29-86 Duration: 22 hours Planned Outage Outage Summary A leak was discovered in the Leak Detection System of Division I Core Spray. The Division I Core Spray break detection transmitter was removed from service. Three valve manifolds and fittings were replaced and the system was returned to service. ECCS System Outage: Division II Core Spray Out of Service from 1830 1-10-86 to 1600 1-16-86 Duration: 142.5 hours Forced Outage 1 Outage Summary Division II of the Core Spray System was declared inoperable when the Topaz Inverter (E21-K601B) for a testability cabinet failed due to a blown fuse. The cause was. suspected to be a plugged screen at the J cooling fan for the unit. The screen was cleaned and the system was i returned to service. ECCS System Outage: Division II Core Spray Out of Service from 2230 5-15-86 to 0900 6-27-86 Duration: 1018.5 hours Planned Outage Outage Summary The Division II Core Spray system was taken out of service to perform preventive maintenance and repairs on the system, The lubricating oil was changed on the "B" and "D" pumps. A local leak rate test was performed on the Loop "B" Pump Suction Pressure Relief Valve, E2 '. -F0'42B. Damage to the Righ Point Vent Valve, E21-F039B, was repaired. The open push-button for Outboard Isolation Valve, a B21-F005B, was repaired. ECCS System Outage: Division II Core Spray Out of Service from 0000 7-12-86 to 0300 7-14-86 Duration: 51 hours Planned Outage Outage Summary System Service Transformer 65 was taken out of service rendering Division II Core Spray inoperable. The purpose of the outage was to add a 345KV intermediate switchyard to improve the reliability of power to the main 345KV switchyard as provided from the Main Turbine a Generator. 15

Fermi 2 l ECCS System Outage: Division II Core Spray Out of Service from 2238 8-18-86 to 1443 5-20-86 Duration: 40.1 hours Planned Outage Outage Summary Division II Core Spray System was removed from service to inspect cable terminations at Outboard Isolation Valve (E41-F005B). During a field inspection it was discovered that external field cable terminations made in recently replaced operators were not made in accordance with Detroit Edison specifications. The cable inspection for E41-P0058 was completed and the cable was roterminated prior to j returning the system to service. ECCS System Outaga,: Division II Core Spray Out of Service from 1015 10-8-86 to 1815 10-9-86 Duration: 32.1 hours Forced Outage Outage Summary Division II of the Core Spray System was taken out of service when the l "B" and "D" pump discharge pressure failed the surveillance test. (Procedure 24.203 05). To correct the probles pressure indicator PI R600B and flow indicator FI R601B were re-calibrated. The test was then successfully completed. ECCS System Outage: Division II Core Spray Out of Service from 0245 11-23-86 to 1400 12-1-86 Duration: 203.8 hours Forced Outage Outage Summary Division II Core Spray was taken out of service when the High Drywell Pressure instrument, B21-N094F, failed the surveillance test (Procedure 44.030 308). However, the overall system response time was within acceptable limits and therefore no further action was required. q, ECCS System Outage: Division II Core Spray Out of Service from 2150 11-23-86 to 1000 12-13-86 Duration: 468.2 hours Planned Outage Outage Summary System Service Transformer 65 was taken out of service rendering Division II of the Core Spray System inoperable. The purpose of the outage was to add a 345KV intermediate switchyard to improve the reliability of power to the main 345KV switchyard as provided by the Main Turbine Generator. 16 s

Far:li 2 ~ ECCS System Outage: High Pressure Coolant Injection Out.of Service from 1255 1-2-86 to 0200 1-6-86 Duration: 85 1 hours Forced Outage Outage Summary During routine sampling of the HPCI oil system an unacceptable moisture content was noted. The oil system was flushed and drained. The lubrication system was then refilled and sampled again. The results of the sampling demonstrated that the oil was within specifications. ECCS Systes Outage: High Pressure Coolant Injection Out of Service from 1435 5-12-86 to 0040 5-21-86 Duration: 202.1 hours Planned Outage Outage Summary The HPCI system was taken out of service to perform a wiring inspection of the operators on the valves listed below. The inspection included a check of the circuitry against the electrical schematic diagrams and was performed because a design error, which could possibly prevent proper valve closure, was discovered on other valves in the plant. This design error was reported in LER 86-025-01 transmitted via NP860536 dated October 3, 1986. No problems were found on these valves. A actor winding inspection was also performed on these valves. In addition, an inspection of the cable terminations at valves E41-F012, E41-F041 and E41-F042 was performed. The inspection was completed and the valves were reterminated prior to returning the system to service. E41-F004 CST Suction Valve E41-F006 Outboard Discharge Isolation Valve E41-F012 Minimus Flow Valve E41-F041 Outboard Torus Suction Isolation Valve -\\ E41-F042 Inboard Torus Suction Isolation Valve ECCS Systen Outage: High Pressure Coolant Injection Out of Service from 0638 hours 8-21-86 to 1555 hours 9-11-86 Duration: 513.3 hours Planned Outage Outage Summary The HPCI system was taken out of service to perfora demonstration tests during this outage. For this purpose the HPCI injection line isolation valve, E41-F006, was closed and de-energized during the tests. During this outage, cable terminations at the Turbine Steam Supply Outboard Isolation Valve (E41-F003), the CST Suction Valve (E41-F004) and the Outboard Discharge Isolation Valve (E41-F006) were inspected. Retermination of these valves was completed during this outage. 17 t

Fermi 2 Outage Summary (Cont') Other work performed included changing the spectacle flange on the return line to the Condensate Storage Tank from the high pressure to the low pressure orifice; recalibrating and functionally testing the pressure differential switch and signal conditioners (E41-N657A and E41-N660A) both of which had failed downscale causing a trip; and various preventive maintenance work orders. ECCS System Outage: High Pressure Coolant Injection Out of Service from 1415 9-15-86 to 2006 12-16-86 Duration: 2214 hours Forced Outage Outage Suasary The HPCI system was removed from service when the inboard and outboard steam supply drain pot isolation valves, E41-F028 and E41-F029 respectively, failed to close when the steam supply stop valve, E41-F001, was opened. The investigation revealed problems with the logic controlling the valves and this was corrected. There was a loss of indication on an excess flow check valve in instrument tubing connected to the Reactor Pressure Vessel which was restored to proper operation. Also, during the outage the inboard and outboard Torus l Suction Valves (E41-F041 and E41-F042) were de-energized to support surveillance testing of the HPCI system. ECCS System Outage: High Pressure Coolant Injection Out of Service from 0845 11-8-86 to 1635 12-29-86 Duration: 1232' hours Planned Outage Outage Summary The HPCI system was removed from service to conduct various preventive maintenance activities. During testing of the HPCI Pump Minimun Flow Bypass Valve a thermal overload trip of the valve operator occurred. The torque switch was found to be defective. It was replaced and the valve tested successfully, he spectacle flange in the return line to the Condensate Storage Tank was changed from low pressure to high pressure orifices. A weld leak was discovered in the Booster Pump Casing Vent Valve, E41-F061, and repairs were made. De minimum flow valve discussed above was de-energized in the closed position on several occasions to accomodate startup testing. The high dcywell pressure transmitter (B21-N094F) exceeded its expected time response as specified in the surveillance procedure (44.030 308). However, the overall system response time was within acceptable limits and, therefore no further action was required. 18 t

F2rai 2 ~ 2.8 Service Life of Main Steam Bypass Line In accordance with Detroit Edison letter VP-86-0154 dated November 7, 1986, the cumulative time the Main Steam Bypass Lines are operated with the bypass valves between 30% and 455 opened will be reported annually. A cumulative value of 100 days is not to.be exceeded without prior NRC notification. Evaluations performed by Stone and Webster and by Hopper and Associates conclude that the bypass lines are acceptable for safe operation when operated within the 100 day constraint. Based on these evaluations, the new mainsteam bypass piping that was installed in 1985 has a service life which will allow itsto remain in service for the life of the plant under anticipated operating conditions. The cumulative value for 1986 is 7.7 days, well within the constraint of 100 days. 19 ,,--,,,---,--.-,,n,-. ,,.-,--m, --,-__----.,.,.-_-,,--.n-,-

Faral 2 30 Facility Changes. Tests and Experiments This section is provided in ace'ordance with the requirements of 10CFR 50.59(b). The regulations allow licensees to make changes in the facility as described in the Safety Analysis Report, make changes in procedures as described in the Safety Analysis Report, and conduct tests and experiments not described in the Safety Analysis Report without prior NRC approval, provided the changes, tests or experiments do' not involve a change in the Technical Specifications or present an unreviewed safety question. 10CFR 50.59(b) requires that a brief description of such changes, tests and experiments, including a summary of the safety evaluation of each, be reported on an annual basis. 31 Design b es The following summary of design changes includes those significant modifications that were completed during 1986. Many of these design changes are not specifically required to be reported by 10CFR 50.59(b) since they do not constitute a change in the facility as described in the Safety Analysis Report. However, they are considered to be significant and warrant mentioning in this report. m 20 1

De2ign Chang 1 Summary Fgrei 2 System A31 Implementing Document No. EDP 5701 Title of Change: Replace Packing in Multiple Valves with Live-loaded Graphite Packing Summary: This design change implemented the replacement of existing valve packing with a live-loaded graphite packing for selected valves. It also addresses capping / plugging of sten leak _off connections which are not hard-piped to a suitable collection / drainage location. Plugging the leak-off connections is necessary since in the new arrangement the connections will be subjected to system pressure. Safety Evaluation Summary: The new packing arrangement is designed to reduce packing leakage and increase packing lifetime, improve valve operation (reduce valve stroke time), reduce packing replacement time (ALARA concern) and eliminate the use of asbestos packing material. i System B21 Implementing Document No. ABN 5585-1 Title of Change: Replacement of Pilot Disc Material for Safety Relief Valves (SRV's) Summary: Eight of the fifteen SRVs' pilot assemblies had new material pilot discs installed. The disc material was changed from Stellite 6B to Araco Alloy Ph 13 8Mo. The new material is expected to reduce corrosion-induced bonding between the pilot disc and its seat. It has been determined that corrosion induced bonding causes high setpoint pressure drift on Target Rock two stage safety / relief valves. l Safety Evaluation Summary: At least eleven of the SRVs must be operable with the specified code safety valve function lift setting (Technical Specification 3 4.2.1). This design change is expected to reduce high set point pressure drift on these safety relief valves and therefore l improve the reliability of the SRVs. l L l 21 .-..,,~~<--,-.--.,y,--_.-,-------,,,n-,,-m-,-w, ,--m,--+---- --am-ne.---,,,,e,.._ _ _- - - -, _ - - ~ - - - _ - - - - -

De3ign Chang 1 Summary Far:li 2 System C35 00 Implementing Document No. EDP 4600 Title of Change: Disable the Division II Alternate Shutdown Panel Summary: ~ In 1985, a dedicated shutdown control panel was installed to provide shutdown capability as described in 10CFR50 Appendix R, paragraph III. With the addition of the dedicated shutdown panel, the Division II shutdown panel, which was provided in the initial plant design to meet Branch Technical Position 9.5-1, Appendix A, was no longer needed. Therefore, in 1986, the remote shutdown panel was disabled. r Safety Evaluation Summary: The Division II alternate shutdown panel was never intended to meet General Design Criterion 19 of 10CFR50, Appendix A. It was a Balance of Plant panel and served no safety purpose once the new dedicated shutdown control panel was declared operable. System C11.E41.E51 Implementing Document No. EDP 1388, 6687, and P11 6731 abd 6736 Title of Change: Modifications to Prevent Overpressurization of the Condensate Storage and Transfer System Summary: The changes involved the addition of an electrical interlock to prevent the condensate storage and condensate return inlet valves from being in the closed position simultaneously; the addition of three pressure relief valves in the combined HPCI, RCIC, CRD and SBFW return line to the condensate return and storage tanks; and replacement of 150f and 300# condensate storage piping components in the combined HPCI/RCIC test return line. The replacement piping and components meet or exceed system design conditions. The fourth change involved relocating the 1" CRD minimum flow line connection to a point where relief protection is provided. Safety Evaluation Summary: Each change ensures against overpressurization and reduces the potential for loss of the Condensate Storage and Transfer system. In addition, this helps to maintain the operability of other affected systems such as HPCI, RCIC and CSS. Overpressure protection was added to bring the Condensate Storage and Transfer system in compliance with ANSI B31.1.0 code requirements. 22

De::ign Changa Summary Farsi 2 Systes C11/C91 Implementing Document No. EDP 5709 Title of Change: Modify Process Computer Software to Redefine Rod Worth Minimizer Minimum Notch Group Summary: his change modifies the Process Computer System software to redefine the Rod North Minimizer minimum notch group from 10 to

18. Rod movements are controlled using this software. It enforces rod blocks and provides error checking and messages if rod movements vary from the predefined sequences. The program is designed to allow up to two insert errors. With only 10 minimum notch groups the same Rod ID is necessarily forced to appear in consecutive groups. When the next to the last rod in a group is selected the softwar9 prematurelv latches up to the next group because it considers the remaining two rods to be the two permissible insert errors. This is per design but could result in operator confusion.

Increasing the number of groups from 10 to 18 makes each group smaller and eliminates the opportunity for a single Rod ID to appear in consecutive Rod Worth Minimizer groups. j Safety Evaluation %= mary: This modification is only to software used by the plant process computer. It reduces the probability of errors by the operator during control rod movements. 1 System C51 00 Implementing Document No. EDP 5100 Title of Change: Addition of Containment Isolation Valves to the TIP Nitrogen Purge Line U, Summary: Two solenoid operated ball valves were installed in the TIP nitrogen purge line. This line provides purge nitrogen to the TIP indexer which is located in the drywell. Previously this line had a single check valve for containment isolation. l Safety Evaluation %==acy: This modification provides isolation features for the TIP nitrogen purge line that more closely match the requirements of i General Design Criteria 56. The same type of ball valves and I isolation signals used for the balance of the TIP system are used in this modification. Therefore, the modification does not l I create the possibility for a new accident or malfunction. The l redundant isolation valve configuration enhances the existing margin of safety. 23 _ _ _ _ _ _ -.--..--..,.,.---+,--,..-,..-,i-,,i----,,..,,...,--- ,ocy--y ,,,or y,.-...-,-

De71gn Changa Summary Feral 2 System E41-02 Implementing Document No. EDP 3623 Title of Change: Addition of Vent "for HPCI Steam Supply Line Drain Summary: The method for draining water that collects in the HPCI steam supply line drain pot is to utilize the EPCI condenser and vacuum. In an outage condition, water must be drained manually. This modification added a vent to break the vacuum in the drain line. The vent consists of a pipe nipple with two manual valves and a pipe cap located in the steam supply line upstream of the HPCI drain pot. Safety Evaluation Summary: The change does'not increase the probability of occurrence or the consequences of an accident because the venting assembly was added downstream of the HPCI isolation valves and within the HPCI room. A steam leak within this room has previously been evaluated. Thus, the possibility of a new type of accident or malfunction does not exist. 1 System E41-02 Implementing Document No. EDP 3706 Title of Change: Hydraulic Bypass Line Around EG-R Actuator i l Summary: To reduce the severity of quick start transients, a Lypass line was installed around the EG-R hydraulic actuator of the HPCI turbine. The bypass provides hydraulic pressure down stream of the EG-R actuator's internal pump prior to HPCI turbine start-up. Safety Evaluation Summary: The modification will allow the system to perform as designed and will reduce undesired turbine trips. 24 j

Design Changa Summary Far:11 2 System E41/T50 Implementing Document No. EDP 5126 Title of Change: Control Transfer Switch Added to Torus Water Level Instrument Isolation Valves Summary: This design change added a transfer switch to the control. circuits of two containment isolation valves in instrument lines to torus water level instruments. The transfer switch will allow j operators to transfer control of these valves from the main l control room to a local dedicated shutdown panel. The control circuits for these isolation valves pass through zones where a fire is assumed to disable the valves and cause the loss of torus water level indication at the dedicated shutdown panel in the hadwaste Building switchgear room. When control is transferred i to the local panel, the control circuits in these zones are bypassed. The availability of the torus water level indication at the dedicated shutdown panel is assured with this modification. Safety Evaluation Summary: The installation is seismic category I and QA Level I. The design change allows local control of the valves and protects against loss of torus level indication. i System G11/T45 Implementing Document No. EDP 6193 Title of Change: Change Pipe Classification for Portion of Piping in Drywell Floor Drain System Summarn The classification of a portion of the Drywell floor drain sump pump discharge line was changed from Group "C" (ASME Section III, Class 3) to Group "D" (ANSI B31.1.0). This section of piping contained fittings that lacked the necessary documentation required for Group "C" piping. The quality assurance and seismic level categories remained the same. Associated I&C components were also changed to a Group "D" classification. The FSAR commits Fermi 2 to Regulatory Guide 1.143 " Radioactive Waste Management System", which requires material traceability for ASME III components. Section B of the Regulatory Guide omits this requirement on sumps and floor drains provided for collecting liquid wastes. This allows the change in the classification of the drywell pump discharge line. Safety Evaluation Summary: 'i The piping remains capable of performing its intended function per the radwaste equipment design requirements of the FSAR. 25 4 .---..~ .-.___.----..---_,--_----.--,._.m-

Design Change Summary Fermi 2 Systen G33-04 Implementing Document No. EDP 5702 Title of Change: Addition of RWCU Steam Leak Detection System Isolation Actuation Thermocouples l Summary: l This modification installed one additional ambient temperature thermocouple in the RWCU Pump Room, Heat Exchanger Room, and l Phase Separator Room. Together with the existing ambient . temperature thermocouples, these new thermocouples provide the required redundancy for the RWCU Steam Leak Detection System. l l Safety Evaluation Summary: i j Addition of these thermocouples to RWCU Leak Detection System was needed to allow the system to meet the failure of a single active l component criteria. l i Systen P11 & E41 Implementing Document No. EDP 3538 l l Title of Change: Addition of Isolation Valves to the HPCI/RCIC Test Return lines i l Suasary: I To perform testing required by Technical Specification, spectacle flanges have to be aligned such that the appropriate sized orifice is installed inline. Isolation valves were added in the four inch test return bypass line and in the ten inch HPCI/RCIC test return line to allow realignment of the spectacle flanges with a minimum of system interruption. j ( Safety Evaluation Summary: The addition of the isolation valves does not affect the l operation of this portion of piping which is non-safety related. i i l l l 26 s

1 Design Changa Suasary Ferci 2 System P11/Y21 Implementing Document No. EDP 6584 Title of Change: Lining of CRT/ CST ' diked area Summary: The condensate storage and. return tanks are enclosed by a single wall which is 3 feet high above the normal grade level. This forms a diked area (approximately 109 feet wide by 232 feet long) which is also excavated 3 feet below grade level. This design change involved installing a waterproof liner over the porous crushed earthen floor of t.he diked area. The liner will facilitate the recovery of water from any leck or spill from the condensate storage tank (CST) or condensate return tank (CRT). SafetyEvaluatic)2 Summary: The effect of lost condensate in the diked area was previously evaluated in the FSAR. The FSAR states that lost condensate in the diked area would be pumped to the radwaste building and that direct accese to Lake Erie, by water seeping into the ground, is inhibited by the clay fill seal beneath the shore barrier. Installation of the liner facilitates recovery of water from any CST or CRT leak or spill and provides additicnal assurance that any lost condensate will be prevented from seeping into Lake Erie. Systen P50 Implementing Document No. EDP 1167 Title of Change: Modification to Station Air Isolation Valve Summary: This change was installed to achieve proper operation of the lV Station Air System isolation valve, V5_2521. This valve was sticking due to high differential pressure (100 psig) across the valve. Furthermore, there were wide variations in the air receiver pressure. A bypass valve was installed to reduce the differential pressure across the valve. A flow control valve, with a locking nut, and a quick exhaust valve were added to the pneumatic control circuit for the valve to resolve the pressure fluctuation in the receiver. Safety Evaluation Summary: l The modifications in this EDP are limited to nonsafety-related portions of the Station Air System. I l l 27

Design Chang 1 Suasary Far::12 4 Systen P44-00 Implementing Document No. EDP 5544 Title of Change: Changing the Operation of EECW/RBCCW i Containment Isolation Valves Summary:. This EDP changed the operation of the containment isolation valves in the cooling water supply and return lines to equipment in the drywell. Reactor Building Closed Cooling Water (RBCCW) is the normal non-emergency cooling water supply to this equipment and Emergency Equipment Cooling Water (EECW) is the emergency supply system. The isolation valves in the supply lines were modified to " auto-close" on the following conditions: a) High primary containment pressure (>1.68 psig, indicative of a small steam line break). b) Low differential pressure (< 20 psig) between the supply and return headers of the RBCCW system (indicative of a loss of RBCCW). c) and loss of off-site power. The isolation valves in the return lines were modified to be operated manually. Previously, these four valves would " auto-open" on low differential pressure (< 20 psig) between the supply and return headers of the RBCCW system. Safety Evaluation Summary: A review of design calculations aetermined that the EECW systes capacity was not adequate to remove drywell cooler heat loads during a small steam line break accident without degrading the performance of other equipment. This change will isolate the EECW from drywell cooling equipment during postulated events, thereby making EECW available for critical loads. An analysis demonstrates that termination of cooling water to equipment in the drywell during postulated small sto u line breaks will not impact a safe plant shutdown. 28 1 m,- ...,w ,,-,-,--,o.,.

De2ign Changa Summary Fsrai 2 System R14-00 Implementing Document No. EDP 5793 Title of Change: Changes to Divistori I 4160V Emergency Bus Undervoltsge Actuation Instruments Summary: i l This EDP changed the following on the Division I 4160V bus: i 1. The trip settings for the degraded grid undervoltage relay were raised from 895 to 95% of nominal. 2. The time delay for the trip settings of the undervoltage relay was increased from 19.2 seconds to 44 seconds. i 3 The bus low voltage alara setting was changed from 955 to 9S% of nominal. t 4. The time delay for initiation of the load tap changer on system service tr'ansformer 64 was reduced from 30 seconds to 20 seconds. These changes were made to correct problems identified during a update of degraded grid relay setpoint design calculations. Safety Evaluation Suasary: This modification required a change to the plant Technical Specification'which was issued August 22, 1986 as Amendment 4 to the Facility Operating License together with the supporting safety evaluation. 1 9 i i d ) 29 i ,,-~ r -,m,, n-,_,,,--,w---w.n-wn,., -,-,aw,.~,..nn.~e,,._,,m, _--w-,, _. _ e-----------

.. ~ _ _ _ _ _ _ i O Design Change Summary Fermi 2 x Sptem 311/S20 Implementing Document No. EDP 1052 j i l Title of Change: Install 345KV Inter' mediate switchyard Summary: s l This modification added a 345KV intermediate switchyard to isprove the reliability of power to the main 345KV switchyard as 1 provided from the Main Turbine Generator. Two 345KV disconneat switches were added and the existing make-up bus at Main Unit Transformers 2A and 2B was reworked to accommodate this change. If either of the Main Unit Transformers were to fail, a plant trip would occur. These new switches would allow isolation of the faulted transformer and subsequent restart of the plant for t operation up t.o 50% power on the remaining transformer. Also, during extended outages of the plant the switches can be opened to isolate the transformers fros'the 345KV switchyard breakers. This allows:the CF and CM breakers to be closed, re-establishing the loop between Bus 301 and 302 to improve reliability of power to the Systen Service Transformer 65 and the Division II loads. Safety Evaluation Summary: j The modifications in this EDP are limited to nonsafety-related 4 systems. System T21 00 Implementing Document No. EDP 4944 Title of Change: Addition of Fire Wrap to Division II Appendix "R" Cable Trays Summary: .'s 1he purpose of this EDP was to add a 1. hour fire barrier to cable i trays containing Division II Appendix-R circuits that are located i within 20'-0" of Division I Appendix-R circuits. The Division I and II Appendix R circuits are located in an area that contains the electrical bus feeding the Dedicated Shutdown control panel. i Safety Evaluation Summary: 1 The additional firewrap was nemied to meet the reautrements of 10CFR50 Appendix "R", Paragraph III.C.E. The added weight of the firewrap does not invalidate seismic design. The weight is i within the design margin of the cable tray hangers. ) 30 t

\\ 7 Design Change Summary Fermi 2 System T22 Implementing Document No. EDP 5391 Title of Change: Modification to Fifth Floor Reactor Building ElHE Summary: This modification required the installation of a plug (22' x 19') in the fifth floor of the Reactor Building through which large equipment, including new fuel, is brought up onto the fifth floor. The plug was changed from 24-inch thick concrete to a hinged steel door for convenience. Safety Evaluation Summary: r This change provides the ease of a hinged steel door on the access hatchway to the fifth floor of the Reactor Building, replacing a heavy concrete plug. The steel door maintains the tornado protection characteristics of the original plug. _____________________a___________________________..______________ System C41 00 Implementing Document No. EDP 1945 Title of Change: Removal of Air Operators from Standby Liquid Control System Check Valves Summary: l The plant had experienced valve packing and limit switch maintenance problems on the Standby Liquid Control System swing [ check valves. These valves are located on the injection line to l the reactor pressure vessel. To eliminate these problems, the valves' testable feature uma removed. This included removal of the associated air operator and limit switches, and installation of a new valve shaft and and bushing. Safety Evaluation % = mary: As a result of the air operator removal, the ability of the valves to perform their safety function remains the same, availability of the valves is increased and valve testing frequency is reduced. The change also reduces personnel-I exposures experienced during calibration and maintenance. i f P 1 I 31 s

Fcrci 2 32 Procedure Changes There were no procedure changss during 1986 which introduced an unreviewed safety question. The following summary of procedure changes are considered to be of significance, warranting mention in this report. Procedure Change Summary i Startup Test Program Changes A number,of procedure changes, which modified the Startup Test Program, were completed in 1986. These procedure changes are summarized below. A safety evaluation was completed for each change to the Startup. Test Program. Copies of these safety evaluations were transmitted to Mr. James Keppler I (Regional Administrator - Region III) via VP-86-0141 dated October 17, 1986. NRC review and approval of l these changes to the Startup Test Program is contained j l in a letter from Region III to B. Ralph Sylvia dated January 15, 1987. The safety evaluations found that none of the procedure changes presented unreviewed safety questions. In each case the change did not result in i condition j previously unanalyzed in the FSAi .Ar did it reduce the margin of safety as defined in the basis of any Technical Specification. No changes were made to the evaluated design and in each case the purpose of the test is still adequately demonstrated. s The following changes to the Startup Test Program were evaluated: l STUT.030.024 Delete Turbine Valve Surveillance Test in l Test Condition 3 Testing will be performed i between Test Condition 5 and Test condition 6 which bounds the testing which would have been performed at Test Condition 3 STUT.03D.030 Delete Recirculation Runback Testing in Test Condition 3 Adequacy of the recirculation flow runback feature to prevent a scram following a feedwater pump trip will be demonstrated during Feed Pump Trip at Test Condition 6. 32 y + - -- -.,. -,,..-.e,me,-- --w-w,c,,, - - - -er.,-.,.,--w,,,w-w- ,,,,---,,.-,,,,,-_,.,-,,,,.,,,--,,-,,,,,----a , _ n a..--, .,ame_.m,

Procedura Changa Summary Far:1 2 STUT.038.030 Delete Recirculation System - One Pump Trip Performed in Test Condition 3 Testing or a single pump trip at Test Condition 6 will be performed to demonstrate the system performance during a single pump trip. STUT.048.023 Delete Feedwater System response testing in Test Condition 4. Testing of the feedwater control system at Test Conditions 2, 3, 5 and 6 provides demonstration of system performance over the entire operating range. STUT.060.018 Delete Core Power Distribution testing in STUT.030.018 Test Conditions 3 and 6. TIP system c operability is demonstrated during power ascension testing when the process computer undergoes the dynamic system test case. + STUT.050.021 Delete Core Power Void Mode Response Testing-STUT.040.021 in Test Condition 4 and 5. System stability is adequately seasured during STUT.050.022, Pressure Regulator. STUT.000.001 Delete testing of the no Reactor Water Cleanup (RWCU) test in Test Condition 3 The no-RWCU test at Test Condition 6 provides the required data to assess the chemical control performance of the RWCU and condensate desineralizer systems. STUT.040.022 Delete Pressure Regulator Testing in Test STUT.050.020 Condition 4 and Backup Pressure Regulator Testing in Test Condition 5 The pressure regulator will be tested at other test conditions that bound the power level of Test Condition 4. Stability data during Test .\\. Condition 4 will be obtained by monitoring of the APRM and LPRM detectors. Testing at Test Conditions 2, 3 and 6 provides adequete demonstration of the capability of the backup pressure regulator to control pressure in the event of a failure of the controlling pressure regulator since these test conditions bound the power level of Test Condition 5. 4 1 33 s ..w ....,,,,,_--,,,,m....m,,mm,mm,,,,.-4,w,.. ..v_,,,.m.m, ___.__,.m.m..,. _,.,_.,m,,, ,,,,_,,,.,_,,,,.m_. ,,m.,,,,

1 Procedura Chang 7 Summary Fer::li 2 Process Control Program Changes A number of new vendor procedures, ishich modified the Process Control Program (PCP), were approved by Detroit Edison in 1986. The changes were necessary because of a change in the solid radweste vendor. In accordance with the new vendor procedures solid radioactive waste is dewatered (versus solidified as previously done) using the Hittmann Nuclear Inc. system. The difference in dewatering is that when dewatering is performed no solidification agent is adued and instead, a more efficient method is used to remove the water from the container to meet burial criteria. This typically allows a larger amount of waste to be added to a given size container. r The new vendor procedures do not represent an unreviewed safety question. The change does not involve equipment important to safety. Technical Specifications require solid radioactive waste to be solidified or dewatered in accordance with.the PCP. Since the dewatering process was included in the Fermi 2 PCP, the change did not reduce the margin of safety as defined in the basis for the Technical Specification for Solid Radioactive Waste Treatment. t h 34 s i

E Firai 2 3 3 Tests and Experiments The fellowing special tests were peiformed on the Emergency Diesel Generators. 49 307.25T Demonstration of EDG #13 Crankshaft Bearing Integrity. 49 307 27T Demonstration of EDG #11 Crankshaft Bearing Integrity. PURPOSE: These test procedures were performed to verify integrity of the upper crankshaft ebearings. The demonstration test will consists of 20 slow starts followed by 10 fast starts then followed by a 168 hour loaded engine run. 49 307 24T Operation of EDG #14 After Upper Crankshaft Bearing Inspection. 49 307.26T Operation of EDG #13 After Upper Crankshaft Bearing Replacement. 49 307 28T Operation of 2DG #12 After Upper Piston Inspection. 49 307 29T Operation of EDG #11 After Upper Crankshaft Bearing Inspection. 49 307 30T Operation of EDG #13 After Upper Crankshaft Bearing Inspection. PURPOSE: These test procedures were performed to verify proper operation of the Emergency Diesel Generator internal engine components following maintenance activities. The amintenance activities were disassembly, inspection and reinstallation or replacement of upper crankshaft bearings or upper crankshaft connecting rod bearings and pistons. SAFETY EVALUATION: Performance of each test required the associated Emergency Diesel Generator to be declared inoperable. A test could only be performed in accordance with operability raquirements of the plant's Technical Specifications. Therefore, no unreviewed safety question exists per the requirements ^ of 10CFR50.59 35 ,-..--.,,,.-,--,,-.,--=-s-,-..,-,-- w.ww, ---p.-, e.---w v.w-.,iwm~.1,-w-%, ,w-w.--s,---,,v-.---,----ww-vt-p.

,-w,--.--w--n,-9,i v.--

+w,-se .4,,.e..

Tmta and Experiidento Fzrsi 2 The following special test was performed as part of the startup test phase. DEMO.HUO.726 Torus Bulk Temperature Determination PURPOSE: This test procedure was performed to verify that the installed torus temperature i instrumentation can adequately monitor bulk j torus temperature. The test procedure includes determining the actual suppression pool heatup rate for one Safety Relief Valve (SRV) open with no cooling. SAFETY EVALUATION: The heatup rate of the suppression pool will l determine the time available for operator i response to a stuck open SRV prior to exceeding 95 F Suppression Pool bulk temperature. Technical Specification 3 4.2.1 allows two minutes to reclose the SRV prior to initiating a Reactor Shutdown. The test ) results ensure that the margin of safety, as 1 defined in the basis of Technical Specification 3 4.2.1, will not be exceeded. Therefore, no unreviewed safety question exists. l l l l 36 ~ - - - - -, ,-v.__-,,,,,e-,e- ..w., ,._.,.-..=__,_._,_._,,_-m_ ,.,,,,.,.,e,,.,

l B. Ralph SyMa Group %ce Premdent Detroit E 10CFR20.407 l % Q "7uIE*a N EE 9 i 10CFR50.59 Reg. Guide 1.16 February 27, 1987 GP-87-0007 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washinton, D. C. 20555

Reference:

Fermi 2 NRC Docket No. 50-341 Facility Operating License No. NPF-43

Subject:

Annual Ooeratino Reoort In accordance with Fermi 2 Technical Specification 6.9.1.4 and U. S. NRC Regulatory Guide 1.16, the Detroit Edison Company is submitting the Annual Operating Report for the Fermi 2 Nuclear Power Plant for the period of January 1, 1986 through December 31, 1986. The 1986 Fermi 2 Annual Operating Report also satisfies the reporting requirements of 10CFR20.407, Personnel Monitoring Repor t, 10CFR50.59, Changes, Tests and Experiments, Technical Specification 6.9.1.5.b (Safety / Relief Valve Challenges), and Technien1 Specification 6.9.1.5.c (Emergency Core Cooling System Outages). In addition the 1996 Annual Operating Repor t includes a section on Service Life of the Main Steam Bypass Line. This satisfies the commitment stated in Detroit Edison letter VP-86-0154 dated November 7, 1986. If you have any questions or comments regarding this report, please contact Mr. Lewis Bregni at (313) 586-5313. Sincerely, cc: J. G. Keppler ~ W. G. Rogers [] J.J. Stefano I A. B. Davis E. G. Greenman f'g II m}}

Retrieved from "https://kanterella.com/w/index.php?title=ML20212J601&oldid=3997662"