IR 05000213/1987022
| ML20236X893 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 12/04/1987 |
| From: | Briggs L, Finkel A, Johnston W, Murphy K, Vankessel H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236X852 | List: |
| References | |
| 50-213-87-22, NUDOCS 8712100343 | |
| Download: ML20236X893 (47) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /87-22 Docket N License N DPR-61 Licensee: Connecticut Yankee Atomic Power Company P.O. Box 270 Hartford, Connecticut 06141 Facility Name: Haddam Neck Plant Inspection At: Haddam Neck, Connecticut Inspection Conducted: August 24 - September 4, 1987 1pspectors:
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. Johnston, Acting D9 rector
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pDivisionofReactorSafety Inspection Summary: Refer to Section 2.0 of the repor Areas Inspected: Refer to Section 1.0 of the repor Results: One violation (failure to provide appropriate quantitative control guides during a safety related flow test). Five weaknesses: (1) several instances of inadequate procedures, (2) two instances of inoperative temperature switches that operate a control room annunciator, (3) need for diverse assurance of pressure isolation integrity, (4) high failure rate of charging pumps, and (5) failure to record as-found equipment condition !
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a CONTENTS INSPECTION REPORT 50-213/87-22 1.0 Introduction and Inspection Scope ... ............................... 1 1.1 Inspection Methodology .... .................................... 1 1.2 Selection of Accident Sequences and Inspection Areas ........... 3 2.0 Summary of Findings .................... ............................ 4 2.1 Discussion of Ma.ior Findings and Conclusions ................... 4 2.2 Index of Findings .............................................. 5 3.0 Emergency Operating Procedures ................... .................. 8 3.1 Loss of Coolant Accidents ...................................... 8 3.2 Lo s s o f El ec t ri ca l Powe r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 3.3 C o n c l u s i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 4.0 Normal and Emergency Electrical Power .............................. 10 4.1 O f f s i te P owe r S o u rc e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 4.2 AC Distribution System ......... ... .......................... 11 4.3 DC Di stri buti on and Battney Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4.4 Natural Disaster Procedures...... ............................. 15 4.5 C o n c l u s i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 5.0 ECCS Functions of the CVCS and RHR Systems ......................... 16 5.1 Charging Pump Availability .......... ......................... 16 5.2 Residual Heat Removal (RHR) Pump Availability . . . . . . . . . . . . . . . . .17 5.3 ECCS Valve Availability .............. ..... .................. 18 5.4 Pump and Valve Surveillance ..... ..... ....................... 18 5.5 Pump and Valve Maintenance ..... ..............................19 5.6 Instrumentation and Controls ....... ...... . ................. 27 i 5.7 Conclusions ................................ .................. 28 6.0 Pressure Isolation Valves ................ ..... ................... 28 7.0 General Observations....... .............. .................... .... 29 7.1 Utility PRA Activities........ ................................ 29 7.2 Human Performance Evaluation System............................ 30 7.3 Component Labelling Program. ............... ................. 30 7.4 Housekeeping... ................. .......... .............. ... 31 8.0 Procedural Deficiencies.. ..... ..... . .. ..... ................. 32 8.1 Residual Heat Removal (RHR) Flow Test. . . . . . . . . . . . . . . . . . . . . . . . . . 32 8.2 Licensee Corrective Actions......... ....... .................. 33 8.3 Root Cause Determination........... . .. ...................... 33 9.0 Exit Meeting... ..... ... ....... .. ............. ... ............ 34 10.0 References... ...... ......... ..... ........ ................... 34 Appendix A - Persons Contacted...... . . .... .... .. .... ........ .... 36 Appendix B - Documents Reviewed.. ....................................... 38 Appendix C - Utility Commitments... ...... . .. .. . ..... ........... 44 ;
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1.0 Introduction and Inspection Scope )
i This inspection was conducted by a team of NRC Region I inspectors to examine safety significant activities and equipment at the Haddam Neck Plant. The lines of inquiry used by the inspector were based on the Probabilistic Safety Study (PSS) prepared by the Northeast Utility Service Company, report N NUSCO 149, February, 198 The report identifies the most likely accident sequences leading to core melt. This section describes the inspection method-
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l ology, the selected accident sequences, and inspection areas that form the i basis for the inspectio Section 2 summarizes the inspection findings and conclusions of the inspec- !
tio This section also provides an index that leads the reader to sections {
of the report where the details of the findings can be foun l
Sections 3 through 9 describe in detail the inspection activities, findings, and conclusion .1 Inspection Methodology The accident sequences identified by the PSS as safety significant were studied and the systems, components and human actions related to these sequences noted. The operating experience of the plant and past inspection findings were also studied. Based on the above, specific components and human activities were selected which became the subjects for inspectio The inspection rationale was to evaluate the operational readiness of the plant by evaluating the availability of the selected components and the capability of plant staff to react and to recover from the selected emergency {
situations. Although, the inspection's primary focus was on the " target" components and activities, programmatic aspects are also evaluated, such as management controls, oversight by quality assurance, training, and human factor A graphic presentation of the inspection rationale is shown in Figure The degree of equipment availability was qualitatively evaluated based on the following criteria, as supported by the performance records, programs, activities, initiatives, observed conditions, and apparent level of personnel competence:
measures to prevent equipment deficiencies or failures (preventive maintenance, trending performance);
prompt detection of failures or deficiencies (surveillance);
effective correction of such findings (corrective ma'.ntenance);
verification of equipment operability (post-maintenance testing, operational testing, calibration, and operational check-off).
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The operation of plant systems and components identified in the selected accident sequences was walked through by the plant staff, with NRC inspectors I observing, during " event simulations" conducted at the simulator, in the control room, and in equipment areas. The operations were evaluated to I
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ascertain that operators were familiar with t he plant equipment and the associated plant procedures during normal, abnormal, and emergency situation The event simulations were evaluated for the operator's ability to utilize control room or local indications, to understand manual and automatic features under the event situations, to use appropriate procedures, and to operate equipment locally and remotely, including alternate train operations. A particular. inspection emphasis was to assure that proper emergency procedures (both symptum and event oriented procedures) were available and capable of being effectively used during the accident situations and under stress, The procedures were evaluated for adequacy, technical accuracy, citrity, and consistenc .2 Seiection of Accident Sequences and Inspection Areas
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Three accident sequence classes and their related equipment failures,. human errors, and recovery actions were selected for inspection. These sequence
' , classes account for the majority of core melt risk, as evaluated by the PSS, and are summarized as follows:
(a) Small and Medium Loss-of-Coolant-Accidents (LOCA)
This accident sequence class is characteri:ad by a small or medium LOCA with high pressure injection initially available, but where high pressure recirculation fails because of operator error or equipment malfunction.
l The inspection included the review of operator capabilities to cope with these accidents and covered all the important PSS identified control room operator error Local recovery actions involving initially failed valves and pumps were also included. The equipment reviewed included those associated with emergency core cooling functions of the Chemical and Volume Control System (CVCS) and the Residual Heat Removal (RHR)
Syste This included the vital pumps, valves, instrumentation, and control equipmen (b) Loss of Offsite Power / Blackout Sequences This accident sequence class is characterized by initiators that place the plant into a transient and at the sar.4 time degrade vital electrical supplies to varying degrees. This includes blackout sequences under which the plant must be stabilized with only DC power available and where offsite or onsite AC power sources must be recovered within eight hours. The class also includes sequences that involve the loss of an emergency bus in combination with operator error or ECCS equipment malfunction. The class includes the failure of Motor Control Center (MCC) Number 5 as an initiating event which fails most ECCS MOVs and vital instrumentation.
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- The inspector addressed this class of sequences by inspecting the human actions that would either minimize the occurrence of long term losses of offsite power or single bus failures. This involved inspecting the incoming 115KV lines and attendant breakers, transformers, and buse Also ~ inspected were the batteries, chargers, supply and tie breakers, transformers, and' relays associated with the individual emergency buse Personnel training and awa. .. ass of equipment testing and operation as well as recovery actions, rhr Jld failures occur, Were also inspecte Special attention was given to the. reliability of MCC-5.
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(c) LOCA Outside Containment
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This accident sequence class is characterized by a LOCA initiated by the failure of pressure isolation valves between the primary coolant system and low pressure ECCS piping. High pressure primary coolant is assumed to fail the low pressure piping outside containment. This event initiates a LOCA, fails parts of the ECCS system..and causes the loss of cooling water inventory, with eventual core mel Though evaluated in the PSS as a low probability event, this sequence class was selected for inspection because it results in potentially significant offsite consequences due to direct bypassing of the containmen The inspection focussed on the pressure isolation valves in the two core deluge lines. Both the isolation "close" function and the ECCS
"open" function of the check valve and normally closed MOV in each l deluge line were assesse .0 Summary of Findings l This section provides an overview of the inspection findings as well as a i l listing and index of each of the deficiencies and observations identified during this inspectio It is important to note that the inspection was 3 strongly assisted by the Probabilistic Safety Study (PSS) program of the l t
Licensee's. This largely voluntary program provided the probabilistic j information and insights used to direct the inspector's lines of inquir '
l 2.1 Discussion of Major Findings and Conclusions t
l Overall, the results of the inspection indicate that the plant staff and l t
the emergency core cooling systems are capable of reliable response to
! the two dominant accident sequences identified in the PSS, Revision 0.
I This conclusion assumes that the maintenance initiatives and recent modifications to the charging pumps will reduce pump downtime and i eliminate shaft breakag .
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The er>rgency operating procedures (EOPs) were found to be technically acceptable. The end result of the various accident sequence simulations placed the plant in the desired condition with the exception of the Blackout Procedure where the end condition, though controlled, was at a higher steam generator (SG) oressure than desired. The Control room and auxiliary operators performed the simulations with a high degree of experience and knowledge, A number of procedural enhancements are being initiated as a result of the E0P simulation Plant equipment was evaluated as having sufficient availability to func-tion as well as assumed in the PS This includes the offsite and onsite electrical distribution systems, the batteries and inverters, and the vital ECCS pumps and valve One area of a possible concern was identified. The charging pumps continue to fail due to shaft breakage and have had high maintenance outage times. Recent modifications to the pumps ar,d improved availability of spare components are expected to alleviate these problems. The licensee actions to assure availability of these pumps in the future will be reviwed by the NRC during routine inspections. A number of concerns having potential for adversely affecting equipment availability were identified, including: lack of breaker resistance acceptance criteria, less than optimum battery acnitoring, defective snotor operator torque switch setting procedure, inoperable RHR seal water cooler temperature switches, and lack of a diverse means of assuring full closure of a pressure isolation valv These concerns are being addressed by ihe license The inspection identified several instances where administrative testing, and maintenance procedures were defectiv Of most significance was a special RHR flow test procedure that lacked sufficient quantitative-control guidance. The test was performed resulting in the overheating of an RHR pump; the cause being the inadequate procedure. This is a violation of ANSI Standard N18.7-1976, Section 5.3.2(c).
2.2 Index of Findings Table 1 frovides a summary of the major findings of the inspectio Note that the table refers to the report section that gives the details of each finding. The Licensee Commitment numbers refer to written instructions from the Station Superintendent to his staff assigning action items and completion dates. These written commitments were provided to the team leader prior to the exit meeting on September 4, 198 These commitments are summarized in Appendix NRC Unresolved Item numbers refer to matters about which more informa-tion is required in order to ascertain whether they are acceptable, are violations, or need further resolution.
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3.0 Emergency Operating Procedures A review of the emergency operating procedures (EOPs) identified in Appendix B-1 was performed by the inspector. In addition, those procedures necessary to cope with and mitigate the consequences of the selected accident sequences were walked through at the licensee's simulator, the plant control room,-
and in the equipment spaces for required local actions. The objective of the walk-throughs was to determine if procedures were technically adequate and if they would provide sufficient guidance to operations personnel to address the selected accident sequences. The walk-throughs also attempted to judge the possibility of operator errors, due to procedural errors or inadequacies, when performing significant activities. The safety risk signi-ficant 1ccident sequences chosen for evaluation are discussed in Section 1 of this report. Within these sequences are specific operator actions that are required to be taken to guarantee successful accident mitigation. These actions address manual operations, both local and remota, to operate or restore pumps and valves, and to perform system lineups under predetermined plant conditions. In all walk-throughs the inspector found the procedure would place the plant in the desired safe condition. However, the inspector did discover a number of areas in which further guidance to the operator
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would enhance the procedures. These were discussed with the licensee. The licensee committed to incorporating further guidance in the E0Ps during the next E0P revision. These items are discussed in the following sequences which were simulated during this inspectio .1 Loss-of-Coolant-Accidents ( LOCA)
Several LOCA events were performed on the simulator ranging from a small to a medium break size These events were conducted to place the plant in a condition that required the operators to go onto either high pressure or low pressure recirculation, an evolution identified as risk significant by the PS High and low pressure recirculation cools the core by using the residual heat removal (RHR) pumps to take a suction from the containment sump and discharge to the suction of the charging pumps or to the suction of the HPSI pumps and to the core deluge heade During the inplant walk-through, actions remote to the control room procedure ES 1.3 required the operator to verify 2500 gallons per minute (GPM) service sater (SW) flow to each RHR heat exchanger. The local gages FI-1401A and B (no other indication) had a scale of 0 to 10 with no units and no marking on either gage to indicate 2500 GP Through discussions, the inspector learned that 2500 GPM had been established during the preoperational testing phase by throttling the RHR heat exchanger SW discharge valves. The valve throttle positions are marked and the valves set to the mar Md position as part of the system lineup. The inspector noted that desired flow could not be assumed because of a predetermined valve position, unless it is routinely verified subsequent to positioning the valve. The licensee initiated two work orders (CY 87 08416 and 08417) to label the gages in GP This action was verified by the inspector during a subsequent tour of the primary auxiliary buildin The inspector also questioned the L____________.____
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acceptable range of SW flow since the procedure did not give a plus or minus allowance. Preliminary information indicates 2200 GPM or above is acceptable. This item, acceptable flow range, is under eval-uation by the licensee's engineering staff. (See Licensee Commitment
- 16, Appendix C).
During the simulator walk-through, the inspector imposed a clogged RHR pump section resulting in a loss of recirculation capabilit This affected entry into ECA-1.1, " Loss of Emergency Coolant Recircu-lation." Prior to entry into ECA-1.1, the operator attempted to shift into Two Path Recirculation (ES 1.4) (in accordance with procedure)
and noted both RHR and charging pump cavitation. Corrective action by the operators to return charging pump suction to the RWST (reverse procedure steps) took about one minute and could have led to pump damage in an actual situatio Cavitation could also occur when shifting to RHR Recirculation (ES 1.3). This was discussed with the license Appropriate procedural changes will be incorporated to alert the operator to possible pump cavitation and appropriate preventive and corrective measures. (See Licensee Commitment #13, Appendix C).
3.2 Loss of Electrical Power Loss of Motor Control Center 5 (MCC-5) and Station Blackout events were selected for procedure walk-throughs and simulator evaluation based on PSS assigned safety significanc Loss of MCC-5 basically results in a reactor trip and loss of ability to electrically operate most motor operated valves of importance. In addition, it requires multiple manual operations to cross-connect air systems (control air -is lost ) and to supply well water to cool service air compressors. During simulation and walk-throughs, the operators were able to control and perform the required actions to place the plant in the desired conditio Through discussion with operations personnel, it was learned that manual actuation of two M0V's would restore charging pump capability should an RCS leak occur that was larger than the metering pump's capacity. The metering pump is a small positive displacement pump used for RCP seal injection during this evolution. The licensee agreed to incorporate the steps necessary to add this increased accident mitigation capability in the Loss of MCC-5 procedure, (EOP 3.1-50). (See Licensee Commitment #8, Appendix C).
Station Blackout results in the plant being in natural circulation with heat being removed by dumping steam from the steam generators (SG), SG inventory is maintained using the steam driven auxiliary feed water pumps. Procedure ECA-0.0 (Blackout) step 16, requires depressurization of intact steam generators to 260 PSIG. This is to be performed as soon as possible to reduce the possibility of Reactor Coolant Pump (RCP) seal damage and a possible resultant LOCA through the RCP seals. During the simulation of this event pressure could not be reduced below about 425 PSIG. This occurred because of the
_ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ ._ .-. _ __ . _ _ _ _ _ _ _
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t
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l high decay heat level and because control air was lost which resulted in the atmospheric steam dump valve failing closed. Other steam bleed paths were not sufficient to reduce the system temperature and pressure to the desired value. The licensee noted that a temporary nitrogen bottle could be easily attached to the atmospheric steam dump valve l operator'to open the valve. This will be incorporated into the proce-dure and an evaluation will be performed to determine if a permanently mounted nitrogen bottle should be installed. (See Licensee Commitment
- 14, Appendix C).
3.3 Conclusions The inspector found the licensee's symptom based procedures to be technically acceptable. The end result of the various walk-throughs resulted in a desired, controlled plant configuration with the exception of Blackout which resulted in a controlled condition at a temperature and pressure above the specified value. Operations personnel taking part in the walk-throughs appeared knowledgeable and well trained. The inspector also noted that valve numbers were not always used in the E0P text. This defect was previously identified in NRC Inspector Report 50-213/87-10 and is in the beginning stages of correction. The inspector also noted that in plant walk-throughs by personnel not directly involved with E0P development / writing would probably identify corrections such as the SW flow instruments (Paragraph 3.1 above) that are taken for granted by personnel that are very familiar with plant system .0 Normal and Emergency Electrical Power 4.1 Offsite Power Sources The loss of offsite power was identified as a dominant initiator in the PSS. The inspection objectives were to review the reliability of the offsite power sources and their connection to station emergency electrical systems and to assure station personnel are capable of recovering from postulated equipment failures. The ,
source of offsite electrical power for Haddam Neck is fed from two {'
independent 115KV transmission lines. One 115KV line is tied with the Connecticut Light and Power Company system at Haddam Substation (line 1206) and the other 115KV line is tied with the Hartford Electric Light Company system at the Middletown generating station through the Canal Substation (line 1772).
Fault relaying is provided for each of the two 115 KV zones of protec-tion which are: (a) line 1772 and transformer 389 and (b) line 1206 and transformer 399. In each case, two independent and separate relay systems are used. They are referred to a primary and back-up group These groups are supplied with current and potential signals from separate current transformers and potential devices. Current and potential circuits for fault detection relays, auxiliary relay circuits, breaker control and trip circuits and 125VDC supply circuits for the primary system are physically separated from those of the back-up syste ,
I
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Normal operation is with line breakers at Middletown, Haddam, and the Connecticut Yankee line sectionalizing breaker 389T399 closed. The Connecticut Light and Power Company and the Hartfurd Electric Light Company systems are synchronize A fault on line 1772 will be detected by the primary and/or back-up line relays at Middletown and Connecticut Yankee. They will isolate the faulted section of the system and transfer the 4160 volt power supply by automatically initiating switching opera-tions as follows:
--
Trip 115KV breaker 389T399
--
Trip 115KV line breaker at Middletown
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Trip 4160 volt bus 1-2 supply breaker 3891
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Close 4160 volt bus tie breaker 2T When one of the offsite power sources is not available, the licensee has the ability to run and load the diesel if determined to be a safety concer The inspector reviewed the maintenance program for transformers, breakers, protective relaying, and the 115KV system. The licensee
'
has a scheduled maintenance program on these devices on a reasonable frequency. The inspector walked down the major components of the 115KV yard at the sit The relays, switches and transformers were well maintained and clean. A review of the maintenance records on the 115KV yard system over the last three years indicated that the devices of the system were within their procedure requirement Recovering of Offsite AC Power There have been three losses of offsite power at this site in the time period January 1,1968 to July 31, 198 None of the events lasted
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longer than thirty minute A review of the emergency calculations (WO No. C2-517-624-RE, Revision 1), December 11, 1985, indicated that the probability of nonrecovery (PNR) was very low. The licensee also demonstrated that during this time period a station blackout (i.e., a total loss of AC power) was supported by the station diesel generators supplying power to the emergency buse No violations or deviations were ideatifie .2 AC Distribution System The inspection objectives were to verify the reliability of the 4160 volt system which included the diesel buses 8 and 9, breakers and transformers associated with these emergency buses. Motor Control Center (MCC)-5 was also reviewed because of its safety significance as a possible accident initiato ___ . - _ . -_____- _ _ - _ - -_
i i i
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The on-site power distribution system includes transformers, switchgear and buses for transmission of the 19KV output from the turbine generator as well as the 115KV input from the switchyard. Normal station power is provided by the three station service transformer Station service transformer 309 steps down the 19KV output from the turbine generator to 4160 volts to feed buses 1-1A and 1-1B. Station service transformers 12R-21S and 12R-22S step down the 115KV offsite power from the switch-yard to 4160 volts and feed buses 1-2 and 1-3 respectively, with the breaker connection to emergency buses 8 and .2.1 480 Volt AC System The Station Service Transformers 4, 5, 6 and 7 (Westinghouse Type SL)
were being replaced during this outage period with Brown Boveri XMTR dry type 4160/480 volt station service transformers (SST). The inspector witnessed the installation of SST No. 6 (No. 496), but the power cables were not connected during the inspection period. Station Service Transformer SST No. 4 (No. 434) and SST No. 5 (No. 485) were installed and operating. The old SST No. 7 (No. 497) was still operating and is to be the last transformer to be replaced. The Westinghouse type SL transformers were removed due to Appendix R requirements (they contain combustible PCB fluid) and the PCB concern posed to personnel. The SST's are provided with a high voltage terminal chamber for termination of the incoming feed from the 4160 volt switchgear. The opposite end of the transformer, the low voltage side, terminates in a bus which ties to the 480 volt switchgea .2.2 Breaker Inspection and Evaluation The 480 volt buses consist of four independent metal-clad switchgear The breakers are drawout 125 volt dc-operated air circuit breaker The switchgear is connected to its respective transformer with sections of metal enclosed bus runs. The switchgear bus can be isolated from its transformer by 3000 AMP normally closed circuit breaker Loads from the switchgear include 50 hp to 250 hp motors and motor control center Westinghouse has a contract for a preventive maintenance program on their DB-25, 50, 75, and EO DHP-250 breakers. The inspector reviewed the preventive maintenance procedures and the work that Westinghouse performed on two DB-25 breakers, one each of a 50 DB, and 75 DB, and 50-DHP-250 breakers. In all cases, the Westinghouse personnel followed their procedures as witnessed by the inspector and with quali" control hold points inspected by the licensee's quality control personne With over 60% of the breakers completed during this inspection period, there were no major problems identified with these breakers. The front and rear tripping latch rollers and pivot pins, tripping trigger and cam pivot pins did not show signs of wear. The spring release latch roller pivot pins and air chutes also showed little wea The overall general appearance of the breakers was clean with little dirt build up in the greased area _ - _ - _ -
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Two observations were made in reviewing the Preventive Maintenance Procedures (PMPs). The first observation was that the PMPs are not consistent in requiring as-found readings to be take This generic concern was first observed while reviewing breaker preventive mainten-
. ance where breaker as-found resistance valves were not being recorde The plant superintendent issued action required forms (See Licensee Commitments No. 6, 15 & 21, Appendix C) which assigned the review of PMP procedures to his staff to determine compliance with ANSI 18.7 -
1976. This is an unresolved item pending the completion of the licensee's review (213/87-22-01).
The second observation dealt with the ductar resistance value from the upper stud to the lower stud for each phase of the Westinghouse DB 25, 50, 75, and 50-DHP-250 breakers. The PMP breaker procedures dealing with this subject (reference Appendix B-2) require the resist-ance value of each phase of the ductar to be recorded, but the accept-ance value has not been established by the licensee. Also, the as-found ,
resistance values are not being recorde The licensee has committed j to establish the acceptance values (see Licensee Commitment #18, Appendix C).
The inspector had no further observations or question .3 DC Distribution and Battery Systems The safety objective of the station batteries is to supply all normal (
and emergency loads for the DC power component In case of a station blackout, the DC battery system is required for the functioning of safety or accident mitigacion components and systems such as breaker, valve operators and inverter The DC system is also relied upon to provide essential monitoring and indicating function The inspection focus was on battery availability with emphasis on possible common cause failure which might af fect the battery system The 'DC system is divided into two divisions. Each division consists of a 60 cell battery and battery charge These batteries are located in separate caged areas in the swi+.chgear room. The vital buses are ,
supplied by four 3KVA single phase inverters. Two inverters feed off i of each station battery system and operate independent of each othe Each inverter is regulated automatically to have an output of 120 volts AC with a 125 volt DC input. The dual supply from separate batteries and inverters provide the required stable and continuous power that is needed during operatio Normally the two battery bus sections are operated independently with the bus tie breaker ope Each charger supplies power for operation of equipment supplied from its associated bus section and maintains a 1 floating charge on its associated battery. The bus tie breaker provides i for parallel operation of the chargers or allows a charger to be taken out of service for maintenance.
(
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Each battery is~ connected to its associated bus section by an 800 AMP circuit breake Each battery charger includes an AC input breaker and a DC output breaker. Each charger also has an AC feeder breaker in line from its respective AC power source (i.e. , MCC-5 for battery charger '
BC-1A and MCC-6 for battery charger BC-18). The breakers associated with the DC system were inspected as part of the overall breaker inspection described in paragraph 4. The inspector witnessed the weekly battery check on the "B" battery system. Using the recorded battery data taken during this surveillanc test, the inspector compared the data with previous recorded data for this system. The values recorded during this inspection period were found to be within the previously recorded data and were acceptabl The following procedures were reviewed during the battery system evaluatio Surveillance Procedure No. SUR 5.5-16, Revision 9, February 15, !
1987, Weekly Station Battery Check Surveillance Procedure No. SUR5.5-17, Revision 8, Quarterly Station Battery Check Gould Stationary Battery Installation and Operating Instructions (Maintenance File No. I-G-34-1).
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PAAR DMA-35 Density Meter Operating Instruction The maintenance department (electrical) is collecting and trending data collected by the above surveillance procedures. The licensee is in the process of upgrading the battery maintenance procedures to incorporate comments from an INPO audit. To assure that the DC system as well as the AC system is not overloaded, the licensee has performed calculations to determine the worst case load connected to each bus. The inspector reviewed the " Diesel Generator Loading" calculation No. PA-78-741-01-GE, Revision 1. This calculation was prepared by the licensee to determine the worst case load connected to the safety-related diesel generator In reviewing the bus loading calculations, the inspector verified that the requirements of RG 1.9 were complied with, RG 1.9 states in part
.... " Predicted loads should not exceed the smaller of the 2000 hr rating or 90% of the 30 minute rating of the diesel generator set".
The 30 minutes rating is calculated to be 2745 KW. This value was based on the data provided in General Motors " Stationary Power Data Block",
April, 1974. The licensee has established the worst case load on the diesel @ 2455K Based on the General Motors study, the licensee's bus loading calculation, and the licensee's method for controlling bus loading, the inspector concluded that the values of RG were complied wit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _
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Bus loadings for the AC and DC systems are reviewed and controlled by the electrical engineering department as well as the plant operating staff.
,
Modifications to the existing plant design are reviewed by the electrical
!
engineering department in addition to other licensee organizations to assure that the requirements of calculation No. PA-28-741-01-GE, Revision 1,-are complied with.
- During the inspection of the battery room area and the review of battery
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test procedures, the reference to cleanliness and battery room tempera-tures and corrosion were not specified in the procedures. The plants'
superintendent issued action required memo's (See Licensee Commitments No. 7, 10, and 12, Appendix C) to address the above observations and revise station procedures as necessar ,
The inspector had no further question .4 Natural Disaster Procedures The Natural Disaster plan for the site was reviewed from the viewpoint of assuring adequate preparation and response in the case weather conditions might affect the availability of offsite power, Abnormal Operating Procedure (A0P) 3.2-5, Revision 5, August 30, 1986, defines !
the course of action to be taken should a natural disaster, such as a hurricane, flood, tornado or earthquake occur, or appear eminen The past history of this site natural disaster and weather conditions have been recorded in F.D.S.A, Volume 1, Section The following automatic actions are taken when the plant enters procedure A0P 3.2- Convex, the dispatch center, notifies the Haddam Neck control i room on hurricanes, flooding, tornados and earthquake statu Hurricanes - After taking all normal plant protection action, a load reduction will begin when wind speed is in excess of 75 mph and place the plant in Hot Standby within six hour (Refer to Emergency Plan for total action that are taken by this site). If the wind exceeds 85 mph, the site is placed in cold shutdown condition. Prior to energizing the 345KV equipment after a hurricane, an inspection of the system is performed to determined the condition of the network, q i
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Flooding, tornado, earthquake - Action on these natural disasters '
is discussed in the site's emergency pla Discussions with various licensee personnel indicated that they were I trained in the above reference procedures and have training on the site emergency pla The inspector had no further question . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ -
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. Conclusions o
The PRA analysis, addressing the electrical system at Haddam Neck, has identified critical systems and components which have been changed or modified during this outage period to increase the reliability of the overall electrical system. Also the results of the PRA analysis are i being used to perform system improvements during future outage Specific loads are being added to the MCC in a new switchgear building j instead of the present MCC 5 based on the PRA analysis performed on '
this syste Electrical procedures that are associated with components in the PRA analysis, and identified as critical to the operation of the
,
system, are being reviewed to determine if adequate steps are identified I in the procedure based on system importance. The maintenance organiza-tion has developed a maintenance program for their safety-related 4160 and 480 volt breakers and is in the process of upgrading their mainte-nance procedures on the station batterie .0 ECCS Functions of the CVCS and RHR Systems 5.1 Charging Pump Availabil3 y In order to meet the head-flow characteristics for high pressure ECCS, the charging pumps P-18-1A and P-18-1B are of a unique design having
, 13 pump stages on a long shaft (about 8 feet between bearings). Shaft l failure is the major contributor to pump failure events.. Over the I lifetime of the plant an average mean time between shaft failure of 2 l years has been experienced. The failure predominates at the end of l the machined thread that accepts the breakdown bushing at the free <
l end of the pump. High cycle fatigue'is believed to be involved.
l The inspector reviewed the pumps maintenance histories (see Section l 5.5, Table 5.5-3) from October 1984 to present and identified three
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shaft failures of the "A" pump and one shaft failure of the "B" pump.-
Overall pump unavailability both from failure to operate on demand and from corrective maintenance outages, since October 1984, appears higher than previous experienc The high unavailability of the charging pump has received considerable licensee and vendor attention. The problem is being attacked on two fronts, the eliminatf or. of shaft failure and the reduction of corrective maintenance outage time, f
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9 The following pump design modifications havi been recently implemented to address the shaft failure problem: j
+
A new shaf t design using key ways to eliminate buildup of shaf t !
end stres i
Improved high ductility shaft materia *
Elimination of stress risers along shaft including a new thrust nut thread desig *
The thrust nut is now of a stress equalization desig *
Impioved rotor balancing as a result of new impeller rotor casing method in addition tc better balancing equipment and method The licensee is in the process of obtaining one complete spare pump rotor package and also a complete replacement pump. It is expected that these spare parts will significantly reduce outage time even if pump problems continue. Maintenance outage does dominate the unavailability of these ;
pumps so this effort is significant to improving pump availabilit ~
The inspector noted that the unavailability used in the PSS does not l account for the most recent failures and outage periods. It is also noted that the PSS pools the actual pump failure data with generic data l using a Bayesian updating approach. Applying a Bayesian approach to a !
pump that is unique and has consistently failed due to the same root cause is not conservative. The inspector calculated a probability of failure on demand, based on 9 failures in 314 demands, to be 3x10 2 which is ten times higher than the value used in the PSS. The signifi- ,
cance of this higher value cannot, at present, be easily assessed as the current ECCS modifications, including the use of the high pressure injection pumps for recirculation, require changes in the PSS plant mode .2 Residual Heat Removal (RHR) Pump Availability '
RHR pumps P-14-1A and P-14-1B have excellent operating experience throughout the life of the plant. The PSS reflects this experience by assigning low unavailability to these pumps. The inspector reviewed the maintenance histories (see Section 5.5, Table 5.5-4) from October, 1984 to present. The corrective maintenance actions are few with only one serious event, motor lead burnout on April 3,1986 (Pump V-14-1A)
that is an apparent pump failure. One failure over a period of three years is indicative of average RHR pump experienc The inspection did not reveal any weaknesses of concern in the mainte-nance or surveillance programs for these pumps, thus, on the whole the 1 pumps are assessed to have acceptable availabilit !
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In reviewing the instrumentation associated with condition monitoring of the RHR pumps, it was discovered that the temperature alarms for the seal water coolers of both pumps were inoperative. An overheating event of one or both pumps would not be alarmed and therefore the confidence of pump availability is affected to some degree. However, the discovery of inoperative temperature alarms, raised more immediate concerns; one dealing with the assurance of operability of alarms (see Section 5.5) and a second one dealing with inadequate procedures (see Section 8.0).
5.3 ECCS Valve Availability Nine ECCS related valves in the CVCS and RHR were identified by the PSS (as well as Reference 2) as being safety significant. These valves were visually inspected and their surveillance, maintenance, and operating histories assessed. Details of the inspection findings are provided in Sections 5.4 and A review of three years of maintenance requests indicate relatively few valve problems with only one valve failure, overload relay failed on BA-MOV-373 on March 21, 198 This single failure in 3 years is indicative of generic MOV unavailability and agrees with the unavail-ability assumptions of the PS The unworkable torque switch setting procedures PMP 9.5-3 and 4 discussed in Section 5.5 raised the possibility of erroneous torque setting However, valve experience does not show any torque setting problem The licensee has committed to correcting this problem, which appears to be procedural in nature, and did not affect valve reliabilit '
The inspector concluded that the selected valves have acceptable availabilit .4 Pump and Valve Surveillance Scope Assess the surveillar,ce program for selected CVCS and RHR components in terms of both Technical Specification (TS) requirements and assurance that the component failure modes identified in the PSS are adequately surveille Discussion The surveillance procedures and histories for the CVCS and RHR compo-nents, as listed in Appendix B-4 were reviewed for the following attributes:
- Ability of the procedure to satisfy the TS and PSS failure mode requirement * Verification of adherence to the test frequency requirements and proper procedure implementatio (
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- 19
l l All of the surveillance completed by the ISI group are stored in the
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Nuclear Records facility. The records are entered in the computer and can be printed out by procedure number. These records were obtained ;
for the. inspection components of the CVCS and RHR and were compared with !
the rctords in ISI, the requirements shown in the applicable technical l specification and the surveillance procedures.
l All of these requirements for periodic testing of valves and pumps are shown in a manual entitled "In Service Inspection Ten Year Program",
Rev, 1, dated June 1, 198 Test schedules have been extracted from this manual in a comprehensive manner. All of the required surveillance tests of the CVCS and RHR components were checked against the entires in the test schedule tracking record, mentioned above for actual tests performed to date. No discre-pancies.were found. It was evident though that some entries were missing in the records provided by " Nuclear Records". These missing entries, however, were mostly traced back to plant outages. The inspector is satisfied that the ISI program is controlled adequatel With regard to the surveillance procedures, it was found that the test frequency was not always shown in Section 2, " License and Administrative requirements of the procedure", but was shown indirectly by referring to the appli-
, cable technical specifications under Section 3, " References". The licensee acknowledged that the test frequency requirements were missing or were not clearly defined in Section 2 of the procedure. They recog-nized this problem themselves and had started a program to revise all of the surveillance procedures to include these requirements. Procedures SUR5-7-68, SUR5.7-92, and SUR5.7-94 will'be included in the above revision program and will have the test frequency requirements clearly 3 spelled out under Section 2 of these procedure .5 Pump and Valve Maintenance Scope Assess the maintenance program for the selected CVCS and RHR inspection components in terms of :
i
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Adequacy of maintenance tracking syste ]
- Adequacy of maintenance record * Adequacy of maintenance procedure *
Significant equipment failures, and actions taken to prevent !
repeat failure, j I
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Discussion The maintenance procedures and histories for the CVCS and RHR compo-nents, as listed in Appendix B-4 were reviewed to accomplish the above mentioned scop Th9 maintenance tracking system is a part of the Production Maintenance Management System (PMMS). The PMMS serves as a record for all mainten-ance activitie It also produces work orders to get future maintenance j work accomplished to a desired schedule. The computer printout lists all information pertaining to the equipment to be repaire In general, the information shown on the work order is adequate. Problem causes, however, are left blank in many instances even though the cause may have been established. An example is the repeat failure of the Charging Pump shafts. A licensee's report on charging pump failures indicates the l difficulty of determining failure cause from the PMMS data (Reference 3).
The licensee has committed to ensuring that work documentation includes the cause of the problem (see Licensee Commitment #1, Appendix C).
I With regard to the maintenance procedures, it was found that the acceptance criteria and the retest requirements (Section 8) are not clearly defined in all cases. .In the case of CMP 8.5-25, acceptance criteria are not provided for the opening and closing time of the l
valve (6.14.6). The licensee said that this data was for information only and that the corresponding surveillance procedure would t6ke the same data and would have acceptance criteria for these dat The data of CMP 8.5-25 would serve as "as-found" dat With regard to PMP-9-5-3, the Acceptance Criteria paragraph 8.1 states that the " torque switch setpoint must match the master setpoint list or ;
as found setpoint" Upon checking out the " master setpoint list", it was found that this list did not exist yet, but was expected to be completed in 6 months. In addition, in saying that the torque switch setpoint must match the "as found" setpoint is clearly an inadequate acceptance l'
criterion. Upon further investigation, it was found that a setpoint list matching the original construction setpoint requirements had been l
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developed in 1985 for both the Crane Teledyne (Reference 4) and the l Limitorque (Reference 5) valve operators. It was required, however, i that these settings were developed for the old accident conditions.
i In a later assignment, PA 86-003 (aimed to satisfy IEB85-03), new torque I
values were developed based on the updated accident analysis. Presently, the new torque values are being used to arrive at new torque switch settings via MOVATS (Westinghouse). It is obvious that procedure PMP 9.5-3, which was signed off by PORC on July 27, 1987 (the effective date), is not being used, and cannot be used at the present time for torque switch setting Instead, torque switches for the crane Teledyne MOVs are being set via MOVATS and the new torque list from PA 86-003, none of which is referred to in PMP 9.5-3. There also is a concern on the timing of the completion of the Master Setpoint List and the com- !
pletion of the torque switch setup of the MOVs of the ECCS and other safety significant systems in accordance with the new torque list from i
PA 86-00 L _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ b
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The licensee has committed (see Licensee Commitment #2, Appendix C)
to ensure that all MOVs, tested under IEB 85-03 have their torque switches set to values derived from MOVATS testing or engineering assessment prior to re-start. This item is unresolved (213/37-22-02).
The licensee also has committed (see Licensee Commitment #3, Appendix C)
to clarify section 8.1 of PMP 9.5-3 and 4 on the verification of the torque switch settings. In addition, the new design data on the MOV torque switch settings will be entered into the Master Setpoint List (see Licensee Commitments #4, #5, and #20, Appendix C). This item is unresolved pending completion of the retesting of the MOV's affected by IEB 85-03. Clarification of PMP 9.5-3, section 8.1, and completion of the Master List (213/87-22-03).
With regard to equipment failure of the valves, it was found that there were few repeat failures. The more significant failures or problems are shown in Tables 5.5-1 and 5.5- The causes of these failur are not always identified in the PMMS record. This observation was passed on to the licensee. Licensee Commitment #1, Appendix C was made to address this-problem. Generally speaking, the failures can be categorized by causes, i.e. operator error, design error and equipment wear and tea With regard to the failures of the pumps, the Charging Pumps A and B, the Metering Pump, and the RHR Pumps A and B (see Table 5.6-2), the more important failures are the shaft failures of the Charging Pump I l
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Table 5.5-1 Failures and Maintenance Actions For Selected CVCS Valves (from PMMS records)
Valve Indent.l Valve Failure / Problem l Date Work Order Closed I l Applic. Pro l l BA-MOV-386 l Overload Heaters Undersized l April 23, 1986 l l M 8.5-126 LD-MOV-200 l Overload Heaters Undersized l May 20, 1986 l J M 8.5-126 LD-MOV-200 l Motor leads w/o Ray Chem Sleeves over l April 22, 1986 l terminals l PMP 9.5-4 l l
- BA-MOV-373 l Vital MOV Overload Relay failed l March 21, 1986 l l SUR.5.7-94
"
l Missing Fasteners l March 22, 1986
"
l l PMP 9.5-3 l Valve Leakage Experienced during l April 15,1986 l Hydro'(Wedge & Seat reconditioned) l 1 I CH-MOV-257 l Failure of Indicating Lights l November 28, 1983 l l
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-l Loss of Control Power (Inadequate l December 2, 1983 l transformer and fuse) l l l BA-MOV-32 l Broken Yoke Sleeve l June 4, 1985 !
l l
"
l Motor has loose bolts l June 4, 1985
- Apparent MOV Failure
- Counted as a control system failure, not a valve failure
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l Table 5.5-2 l Failures and Maintenance Actions for Selected RHR Valves (from PMMS records)
Valve T,ndent.l Valve Failure / Problem l Date Work Onfor Closed'
l l Applic. Pro l l \
FCV-796 l Valve do not close fully, loose nuts, l April 14, 1986 l chain prevented Positioner Arm l l movements l l 1
"
l April 1, 1986
,
l Valve will not reduce RHR flow to '
l less than 2000 gpm (replaced l l positioner) l l l FCV-602 l Valve will not reduce RHR flow to l March 10, 1986 l less than 2000 gpm l l I RH-MOV-33A l Packing Gland Lea l March 19, 1986
. 1 I RH-MOV-338 l Packing Gland Leak l March 14, 1986 l l NOTE: No apparent valve failures affecting ECCS performanc l
4 l
l l
- - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _
- - _ - _ _ _ - - _ _ -- . __
.
.
Table 5.5-3 Failures and Maintenance Actions for Charging Pumps (from PMMS records)
Pump Indent. l Pump / Motor Failure / Problem l Date Work Order Closed l l Applic. Pro '
l l P-18-1A -l Motor bearing shaft surfaces coming l April 30, 1986 l loose (spray weld); brass filings in
.
l PMP 9.5-8 l oil l CMP 8.5-28 l l
"
[ Install new motor l April 19, 1985 l .
I
"
l Replace motors; brass filings in oil l April 25, 1986 l l PMP 9.5-25 l l CMP 8.5-112 l l CMP 8.5-139 I I
"
l Replace rotating element l October 6, 1984 l l SPL-105-179 I I
- " l Broken shaft, pump frozen l June 18, 1985 l Replace rotating assembly l M-8,5-28 & 141 I I
"
l Replace gaskets l May 29, 1985 l l
- " l Broken shaft diagnosed for erratic l July 29,1986 l pump performance l l l
"
l Recirc Valve is noisy, closed too muchi March 26, 1987 1 I
"
l Burrs and raised metal on split rings,1 May 13, 1985 l shaft and sleeves l ;
I I
"
l Lube o11 return line hose is deterio- l July 30, 1986 l rated, replace l CMP 8.5-141 I I ,
- " l Broken shaft, repair, reassemble lAugust 26, 1986
'
l l CMP 8.5-141 I I
"
l Impeller hubs failed step 6.2.17 l August 25, 1986 i l of proc. CMP 8.5-141; Rework hubs l l l
"
l Nut galled to shaft during testing l August E2, 1986 l l 1.e., the balancing sleeve locknut l l l l
"
l Locknut galled to pump shaf t; threads l July 30, 1986 l repaired l l l l
- Apparent pump failures l
- _ - _ _ _ _
- __ _ _
1 y
.
!. 25
.
Table 5.5-3 (Continued) )
-l Failures and Maintenance Actions for Charging Pumps i (from PMMS records)
Pump Indent. l Pump / Motor Failure / Problem l Date Work Order Closed l I Applic. Pro I l l 1 P-18-1B l Replaced Motor l July 8, 1985 l l M 8.5-28 I I
"
l Motor Bearing Problems, Rebuilt motor l May 9, 1985 l shaft and end bells, rebebbit bearings l I l
"
l 011 Leak Inboard Bearing l February 6, 1985 l l
"
l Installed EEQ Terminals l May 1, 1986 l l PMP 9.2-25 l l
"
l Replace motor mounting pads l August 28, 1986 l l l SPL-10.5-178 l l
"
l Sight Glass has oil leak, lower gasket l December 20, 1983 I l
"
l Installed spare motor, reversed fan l October 25, 1984 l for proper rotation l PM 9.5-24 I I
"
l Installed spare motor l November 3, 1984 I I
"
l Motor protection relay settings were l November 9, 1984 l changed l 1 l
"
l Motor screens plugged by insulation l November 9, 1984 l dust from work above motor l l l
"
l Oil reservoir leaking from bottom l January 17, 1985 l fitting l l I
"
l Oil reservoir leaking from bottom l January 17, 1985 l fitting of sight glass l 1 I
"
l Loose support brackets of casing l November 27, 1985 l drain lines l l l l
- " l Pump shaft failure l May _ , 1985 l l
"
l Bypass valve to aux. cooler needs l May 13, 1986 l repair l j
'
l I
- Apparent pump failure l
i I
q
_ ._
i
, - - -
_ _ _ _ - - _ - _ _
.
'
.
Table 5.5-4 Failures and Maintenance Actions for RHR Pumps (from PMMS records)
Pump Indent. l Pump / Motor Failure / Problem l Date Work Order Closed l l Applic. Pro I i
"
l RTD Conduit of Seal water supply l February 8,1984 l was split, wire is rubbing, repair l l conduit l l l
"
l Gland seal leaks around shaft; l August 23, 1984 l Replace seal l M 8.5-99 I l i
"
l Leaky gasket on discharge flange; l April 12, 1986 l Corroded study and nuts l
l l P-14-1B l Oil found to be black; filled and l February 3,1987 l drained 9 times to clear the oil l
'
l l
"
l Pump discharge flange has leaky l March 29, 1986 l gasket and corroded studs; Replace l l l
"
l Oil leak on pump; oil seal bushing l May 13, 1986 l worn l l I
- Apparent pump failure i
t
- - _ _ _ _ _ _ - - . - - _ _ - - -_-_]
_ _ _ _ _ _ _
.
.
5.6 Instrumentation and Controls Several instruments were pre-selected for review that were associated with the safety significant components identified in the PSS. These instruments included:
- RHR Seal Water Cooler Temperature Switches TS602A&B
- Pressure Interlocks on Pressure Isolation PC-404A Vaives MOV-803, 804, 780 & 781 PIC-403
- RWST Level Instruments LA,LI,LT 1806A&B
- Sump Level Instruments LT, LS 1803 The calibration and surveillance procedures of the selected instruments were evaluated for their technical adequacy and the test results of the past two years were reviewed to verify that:
Instructions were adequate to perform the test *
Tests were performed and documented according to the procedure *
Test instruments were calibrated using primary and secondary calibration sources traceable to the National Bureau of Standard *
As-left test and calibration results met the acceptance criteri *
Procedures included Precautions to prevent equipment damage and protect personne *
Instructions included adequate return-to-service requirement *
Test results were reviewed by licensee and timely corrective actions taken as necessar *
Repetitive failures were evaluated and preventive measures take Appendix B-5 lists the documents and test results reviewed. Within ,
the scope of this review no unacceptable conditions were identified j with the exception of temperature switches TS 602A& j l
No calibration records were found for temperature switches TS 602A& These switches are designed to provide a control room alarm if one of the two RHR Seal Water Coolers shows an overtemperature condition (alarm set a 180 F). It was discovered'that no calibration tests had been performed on these switches. In addition, in response to an actual RHR Pump B overtemperature event on 12/21/86, the Licensee discovered that the switches, a: parently had never been connected to the control room alarm panel. The inspection team reviewed the events leading up to the overheating event as well as the concern involving the dis-connected temperacare switche Section 8.0 documents the inspection findings involved in the pump overheating event, that in part, involves a violation of technical specification administrative requirement The disconnected temperature switches raised the concern as to whether this deficiency was an isolated case or whether other annunciators !
were inoperative. The Licensee has committed to review all control I room annunciators to assure that there exists documentation proving annunciator operabilit This effort will be completed prior to plant startup (See Licensee Commitment #9, Appendix C) and is carried as an unresolved item (213/87-22-04). The inspector had no further concerns regarding I& :
__ ._ _ _ _ _ _ _ . __ _ __ -- _ - - _ _ _ _ _ - - _ _ _ _ - _ _ _ - _ _ _ _ _ _ .____ _ _-- _ _
.
.
!
5.7 Conclusions The inspector found, with the possible exception of the charging pumps, that the ECCS equipment including the safety significant valves and pumps have adequate availability to perform their ECCS functions, especially those required for the small break and medium break accident sequences which were the focus of the inspection. As to the charging pumps, their actual availability is less than that used in the current PSS and thus are cause for continued licensee attention to effect improvement .0 Pressure Isolation Valves As described in Section 1.2(c), certain pressure isolation valves have signi-ficant safety importance as their failure would cause an unmitigated LOCA outside containment. The PSS identified a number of such valves, with the valves in the core deluge line being most important. The inspector concen-trated on these valves; SI-MOV-871A&B and SI-CV-872A& Both the pressure isolation (closure) function and the ECCS (open) function were reviewe Each core deluge line (6" diameter) contains one check valve followed by a normally closed M0V. The MOV is actuated in the event of a safety injection I signal. The valves are located on the removable portion of the reactor vessel head. Thus during refueling outages, the MOV is electrically. dis-connected as is the deluge piping via a removable spool piec The internal design features, the surveillance and maintenance procedures and histories of these valves were reviewed and the valves visually inspected (during the inspection the upper head was off and located in the head laydown area).
As concerns the ECCS (open) function of the valves, no discrepancies were discovered, experience indicated that the valves had operated open in a reliable manner. The inspector inquired about the retesting of the MOV once the head is replaced, i.e. , once the electrical harness was reconnected, was the valve operated to test for the open function? Review of the start-up ,
procedure (SUR 5.1-1) and the valve maintenance procedures (CMP 8.5-3 and '
SUR 5.7-64) along with interviews with the electrical and mechanical mainten-ance personnel provided assurance that the MOVs were adequately teste A minar procedural correction will be implemented to ensure that electrical post-maintenance verification is referenced as being required as part of the start-up procedure (SUR 5.1-1). This change reflects current practic The inspector had no further question The pressure isolation (closure) functions of the check valve and MOV were addressed. The check valve is leak tested as the system is coming up to pressure (at 350 PSI). Experience to date indicates that these check valves are essentially leak tight. The internal design of the check valves (Rockwell Tilting Disk) were reviewed in terms of disc, bearing, and hinge pin design against possible internal disassembly. This review showed the valves to be conservatively designed providing further assurance against failur _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ - _ __ _ _ - -
__ -_ -.
__ __ _ _ _ _ - - - ______ - _ _ _ - -
.
.
The MOV's are 6" Crane gate valves with a Crane Teledyne motor operato These valves are not leak tested. The inspector raised the concern as to the confidence that the MOV's are, in fact, fully closed at startup; these valves are exercised a number of times during the startup evolutio Currently only the motor operator position indications r.re relied on to demonstrate valve closure. The Licensee has committed to developing a diverse means of assuring full MOV closure at startup. A method employing motor operator current versus time measurements is being considered. This commitment is considered an improvement to the current startup procedur (See Licensee Commitment #17, Appendix C). This item is unresolved j (213/87-22-05).
The inspector noted that the PSS probabilistic analysis of the possible failure modes of the closed MOV-check valve configuration in the deluge lines assumes the MOV is close The analysis does not assess the possibility of a leaky or partially open MOV nor does it analyze the possibility of an inadvertent safety injection signal opening the MOV with subsequent check valve failure and failure to reclose the MOV. These observations were discussed with the PSS analysts in addition to questions concerning the thermohydraulic aspects of this class of accident sequenc The analysts have indicated that these concerns remain as an open ISAP issu .0 General Observations 7.1 Utility PRA Activities The utility's PRA staff continues to provide support for the Integrated Safety Assessment Program (ISAP) for both Millstone 1 and Haddam Nec The staff is also involved in the PRA work on Millstone 2 and 3. The inspector noted two important utility PRA activities as they related to this inspectio PRA Staff Involvement In Design Modification Review As an outgrowth of the ISAP issues prioritization work, the utility's PRA staff is now in the design change approval chain. The staff has provided important inputs to design decisions using such techniques 4 as fault tree modelling and failure modes and effects analysis. The PRA staff's involvement has advanced to the point where design reviews are being conducted not upon completion of a modification package but during the early stages of conceptual development. It was clearly evident from interviews with both design engineering staff members and the PRA staff that the design and implementation of ISAP Topic #2.15 concerning "Long Term Small Break LOCA and ECCS Modifications" involved close ties between the two organizations throughout design developmen This close relationship will assure that probabilistic design review methods will compliment the deterministic methods providing further assurance that future modifications favorably impact plant safety, i
_ --_-_
- - - - - _ - _ _ _ _ _ _ _ _ _ - .
,
.
.
Planned Revisions to Haddam Neck PRA This inspection was bcsed on the PSS, Revision 0, issued March 1986, which was limited to internal event Subsequently, a fire study and an internal flood study were issued. These studies have prompted a ,
number of important safety improvement efforts involving modification of the ECCS systems and installation of a new switchgear building. The utility plans on updating the PSS after each major outage that involves significant safety upgrades. A major PSS revision is expected after the 1988/89 outage when the major ECCS modifications have been complete .2 Human Performance Evaluation System During discussions with Licensee management regarding the importance of determining the root cause of safety significant events, a licensee initiative, the " Human Performance Evaluation System (HPES)" was men-tiened. The inspector held further discussions with HPES personnel to provide further details on this initiative. The systems' purpose is to understand and help resolve events that occur at the site involving questions of human performance, see Reference 6 for policy statemen The system uses a number of investigative approaches such as " casual event charting" to understand the root causes and contributing factors cf events or "near misses". The system is relatively new at Haddam Neck but has been used at Millstone. Several investigations have been con-ducted with positive result The inspector reviewed HPEC Report C-87-002 regarding a collision of two containment cranes (Reference 7).
The conclusions and recommendations of the report show the system to be effective in finding the root cause and providing management with recommendations for the elimination of future similar events. This initiative appears to have potential for assuring that operational experience is analyzed and acted upon effectively by plant managemen .3 Component Labelling Program The inspection team observed room signs, component labeling, control and instrument labeling, as well as naming consistency in plant documentation and procedures. The rationale of this activity was the minimization of human error or delay during emergency evolutions or maintenance activi-ties because of misidentification of component . Labelling Status In general, the degree of component labelling and its consis-tency in documentation at Haddam Neck, within the scope of the inspection, appeared adequate with no substantial defects identified. Certain aspects of labeling are in the process of being improved. The inspection findings regarding labelling are as follows:
Component naming consistency in E0P's as discussed in Section 3 3 valve numbers are not always used in E0P' This supports a previous inspection finding 50-213/87-1 _ _ _ _
_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ . _ _ _ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
l
- Consistency in instrument units of measure - as discussed in Section 3.1, the units of measure in a procedure should be consistent with that on a referenced instrumen Consistency in MCC breaker naming conventions - it was observed that the three inch black letters used on MCC-5 did not use a consistent naming conventio The above inconsistencies were judged to be restricted to a small number and not to be a substar,tial problem at Haddam Neck. However, the licensee is conducting a procedure upgrade program as well &s a component labelling program and has indicated that the above findings involving " consistency" will be addressed in these program . Labelling Program The inspector observed the results of an ongoing component labelling program. New blue tags have been placed on pumps and valves in the plan Interviews with the individuals in charge of labelling indicate that INP0 recommendations have been incorporated into the program and that care is being taken to establish component noun names acceptable to the operating staf Verification of correct labelling is also
-
being conducte The labelling program appears to be an important licensee initiative. The inspector determined that management control of the program could be improved as the result of the following observations:
-
no formal program scope and objective exists
-
no formal labelling standards have been written though INPO recommendations have been informally adopted
-
no formal QA oversight has been established
-
coordinatic and consistency between mechanical, electrical, end I&C labelling efforts are not apparent These observations w*re discussed with plant managemen A commitment was made to formalize the labelling program (see Licensee Commitment #11, Appendix C).
7.4 Housekeeping j t
During routine tours of various plant areas, the inspector noted that '
general Housekeeping conditions and plant cleanliness were satisfactor The plant ad a loc level of contamination in containment as was evident in that niost a mas w're accessible wearing only a lab coat, shoe covers and gloves. Two oL:cevations were identified to the licensee who corrected both conditions. The first observation was the dirt in battery cage B, which is discussed in paragraph 4.3 and the second observation was two pieces of 1 inch angle iron laying loose in the
___ _ _ _ - _ - _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - . ______ _
~
.
containment ventilation exhaust duct, outboard of the containment purge isolation butterfly valve. The angle iron, which was 3 feet long by 1.5 inches thick, was removed by work order CY 87-08571 and the butterfly valve and seat surfaces were examined with no adverse findings. The valve is pressure tested and placed in the closed position during the full operating cycle, therefore, the angle iron was determined not to present a safety problem. It was also determined that any air flow through the duct would tend to move the angle iron away from the valv The inspector had no further questions concernir;g these matter .0 Procedural Deficiencies This inspection identified a number of procedural deficiencies, for example:
Section 3.3 concludes that minor deficiencies in the E0P's could be identified if the licensee conducted independent procedure walkthroughs {
similar to the ones conducted during this inspectio *
Section 5.5 reports approved motor operator torque switch setting procedures that were unworkable and not being use Section 7.3 reports a plant labelling program not controlled by a procedur In addition to the above, several further findings were made that involve procedural deficiencie These findings concern a special RHR flow test conducted on December 21, 198 This section described the background and findings associated with the tes .1 Residual Heat Removal (RHR) Flow Test A special one time RHR flow test was conducted on December 21, 198 The purpose of the test was to determine the throttle position of flow control valve FCV-796 in order to meet certain LOCA requirements recently identified by the license Special Maintenance Procedure SPL 10.7-273 was developed for the tes Several safety evaluations were made in accordance with Nuclear Engineering and Operations Procedure NEO 3.12, Safety Evaluations to satisfy 10 CFR 50.59 requirements. The test required flow through FCV-796 with one RHR pump running and the valve to be throttled to adjust the flow to 1500 gpm 200 gpm. Once this flow was achieved valve collar measurements were to be taken. Precau- !
tions indicated that cooldown of the RCS must not exceed 50 F. This I was to be satisfied by throttling the RHR heat exchanger Component Cooling Water (CCW) outlet valves. The procedure did not specify any limitations on CCW throttlin ,
_ _ _ _ _ _ . . _ . . _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
___ _ _ .
.
.
The shift supervisor on duty during the test indicated that to control RCS cooldown he had to severely throttle CCW flow (he indicated that the flow as throttled to approximately one tenth of normal flow., e.g.,
150 gpm opposed to a normal flow of 1500 gpm). The test was completed and the systems returned to normal. On January 5,1987, black oil was discovered in RHR pump "B". It was determined that the oil temperature
.had exceeded 240cF and the oil was partially carbonized. The overheating of the pump was traced back to the special flow test. It was determined that the throttling of the CCW system resulted in insufficient cooling-water to the Seal Water Cooler of pump "B". On March 18, 1987, it was further determined that the Seal Water Cooler overtemperature a' arm that should have activated at 180 F and thus warn the operator e' an RHR pump problem was inoperative. It was discovered that temperature switches TS 602A&B had never been connected to the alarm (see Section 5.6 for further discussion of the temperature switches).
8.2 Licensee Corrective Actions Upon discovery of the black oil in the RHR pump "B" the licensee immediately ran vibration tests on the pump to determine if the high temperature had caused pump degradation. It was determined that the lubricating properties of the oil had not been effected and pump vibration levels were normal, after which the pump was considered operable. Upon determination that the TS 602A&B thermal switches'
were disconnected the licensee planned to obtain new switches and to install and connect them at the next outage. No further licensee actions were taken prior to the inspectio .3 Root Cause Determination The inspector reviewed the procedure, the associated safety analyses, and interviewed the test engineers and operators associated with the tests in order to determine the root cause of the pump overheating '
event. It was determined that the procedure had been properly followed as written and no implementation discrepancy had occurred. The proce-
' dure contained the following:
" NOTE: Throttle RHR HX CCW outlets as necessary to minimize <
cooldown effect of steps 6.3.2 through 6.3.4". '
l The operators had followed this note and unknowingly caused pump over-heating. The most direct violation of requirements in this case was the fact that the parameter, " col flow", was not adequately quantified as i required by ANSI Standard N18.7-1976, Section 5.3.2(6), which requires 1 parameters to be quantified where appropriate. A certain degree of l urgency is indicated by the records and may have been a contributing '
factor; the safety analyses are dated 12/17/86, the procedure approved 12/18/86, and the test conducted 12/21/8 It is, certain however, that in developing the procedure and in reviewing its potential impact the analyses were insufficient to identify the effects of severe CCW throttlin _ _-
_ _. __ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _
_
l 34 i
.
Among the possible root causes is one that certainly needs licensee attention. The particular test in question had two distinct aspects: A permanent .RHR system change consisting of the throttling of l- FCV-796, and ( A one time test to set the valve's position.
l l The safety analysis and the governing procedure, NE0 3.12, all. stress
!
<
the safety analysis of the permanent change with less concern about .!
l the possible adverse affects of the tes The fact that the reactor g was shutdown during the flow test may have caused reduced vigilance on i
"
the part of safety review team, but as the flow test demonstrates, a poorly designed test evolution may result in equipment damage not .
immediately detectable and the subsequent operation of the reactor with degraded equipmen As indicated in Appendix A of the cover letter, Procedure SPL 10.7-273 is considered inadequate and is a violation of the licensee's technical specification and ANSI N18.7-1976. As part of the response to this
!
violation, the licensee is expected to conduct an independent root cause analysis of the violation and associated event Part of this analysis should address procedure development and procedure review requirements that would minimize the occurrence of events similar to the RHR pump overheating of 12/21/86. This is a violation (213/87-22-06).
9.0 Exit Meeting The inspection team met with Licersee representatives (denoted in Appendix.A)
l at the conclusion of the inspection on September 4, 1987. The team leader j summarized the scope and findings of the inspectio .0 References Report NUSCO 149, " Connecticut Yankee Probabilistic Safety Study,"
NUSCO, February,198 . Report EGG-RE0-7601, "PRA Application Program for Inspection at the Haddam Neck Nuclear Power Station", draft report, INEL, March 198 . Memorandum of Northeast Utilities, from N. S. Hersig to R. C. Beganski,
" Evaluation of the Connecticut Yankee Charging Pumps, dated March 2, 198 . Memorandum PSE 85-217 from Northeast Utilities, from N. R. Kollengode to Ron Carrinati, " Torque Switch Evaluation for Motor Operated Valves -
Original Torque Switch Setting Valves from Portersville Teledyne", dated April 1,1985; w/ attachments on torque switch settings.
l
... . _ - - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ . .
__
_ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ -
.. .
-
'
5. Memorandum PSE 85-921 from Northeast Utilities, from N. R. Kollengode to Ron Corrinati, "Terque Switch Evaluation for Motor Operated Valves
- Original Torque Switch Settings from Limitorque Corporation", dated September 18, 1985; w/ attachment on torque switch setting ~
, 6. Millstone Administrative Policy MAP 1.07, Rev. 1, " Human Performance
!.- Evaluation System," 2/4/87 (said to apply to Haddam Neck).
7. Memorandum C-87-002 from Northeast Utilities, from D. G. Casey to
-
P. B. Miller, " Collision Between . Containment Polar Grane and Containment Manipulation Grane,"-August 12, 1987.
L f
I L
l
l
_ _ - -___ -
e c
4 Appendix A Persons Contacted Utility Personnel J..Aubrey, PRA Engineer, NUCSO
- Bartron, CY Maintenance Supervisor, CY G. Bauchard, Unit Superintendent, CY J. Beauchamp, Quality Services Supervisor, CY W. Belovich, Control Room Operator (RO), CY
- J. Bickel, Supervisor, PRA, NUSCO
- M. Bonaca, Manager, Reactor Engineering, NUSCO W. Bousman, Control Room Operator. (SRO), CY
- M.-Bray, Assistant Supervisor, Simulator Training, NU
-*R. Brown, CY Operations Supervisor, CY J. Calderone, ISI Engineer, CY
- R. Caminat', CY Maintenance, Elect., CY J. Chiarella, Assistant I&C Supervisor, CY J. Clark, Principal Engineer
- E. DeBarba, Station Services Supt., CY J. DeLawrence, ISI Engineer, CY
- J. Evola, Maintenance Engineer, CY R. Gracie, Operations Assistant, CY
- R. Guilnette, PMMS Planner - Maintenance, CY
"W. Heinig, CY Quality Services, NUSCO
- J. Hirs1, Engineer, NUSCO R. Kaci,:h, Licensing Manager R. Kasuya, Engineer, CY M. Lederman, Licensing Engineer, NY P. L'Heureux, Assistant Engineering Supervisor, CY
- D. Miller, Jr. , CY Station Superintendent, CY
- L. Nadeau, Manager - Generation Projects, NUSCO R. Necci, Engineering, NU
- T. Neviccio, CY Public Information, CY P. Rainha, Supervising Control Room Operator (SRO), CY
- D. Ray, CY Engineering Supervisor, CY R. ' Reeves, Control Room Shift Supervisor, CY J. Rein, Simulator Instructor, CY R. Rogozinsky, Mechanical Engineer, CY W. Romberg, Vice President, Nuclear Operations, NU B. Ruth, Manager, Operator Training, NU G. Tylinski, Elec. Engineering, CY
- vanNoordennen, Supervisor, Nuclear Licensing, NY
- S. Vick, Licensing, NUSCO J. Waig, Senior Simulator Instructor, CY S. Weyland, Mechanical Engineer, NU N. Young, Senior Simulator Instructor, CY
- - _ - _ _ _ _ _ - - - - _ _ . - - - _ - . _ . . _ _ . .
- - -__ - _ _ _ .
l
l 37
. U.S. Nuclear Regulatory Commission
- A. Asars, Resident NRC Inspector, Haddam Neck R. Barrett, Branch Chief, Risk Application Branch, NRR l
'
- L. Briggs, Senior Reactor Engineer, Region I l
'
K. Campe, Section Leader, Risk Application Branch, NRR J. Chung, Senior Reactor Engineer, Region I
- A. Finkel, Senior Reactor Engineer, Region I
- Johnston, Director, DRS, Region I
- K. Murphy, Technical Assistant, DRS, Region I
- T. Shedlosky, Senior Resident NRC Inspector, Haddam Neck
- H. vanKessel, Reactor Engineer, Region I
- Individuals present at the exit meeting on September 4,198 The inspectors also contacted other personnel including, control ron operators, auxiliary operators, I&C technicians, maintenance workers, and contractor personnel dering the course of the inspection.
l l
l t
,
(
c-
.;
3 .
Appendix B Occuments Reviewed B-1 Emergency Response Procedures B-2 Electrical Documents B-3 Mechanical Documents B-4 Surveillance and Maintenance Procedures B-5 Instrumentation and Control Documents
_ _ _ _ _ - _ _ - _ _ __ - -
_ _ - _ _ _ _ . - _ - _ - - _ - -
-
.
B-1 EMERGENCY RESPONSE PROCEDURES Number Title E-0 Reactor Trip or Safety Injection, original ES- Rediagnosis, original ES- Reactor Trip Response, original ES- Natural Circulation Cooldown, original ES- Natural Circulation Cooldown with Steam Void in Vessel (with RVLIS), original ES- Natural Circulation Cooldown with Steam Void in Vessel (without RVLIS), original E-1 Loss of Reactor or Secondary Coolant, original ES- SI Termination, original ES- Post LOCA Cooldown and Depressurization, original ES- Transfer to RHR Recirculation, Revision 1 ES- Transfer to Two Parth Recirculation, Revision 1 ECA-0 0 Station Blackout, original ECA- Station Balckout Recovery Without SI Required, original FCA- Station Blackout Pacovery with SI Required, original ECA- Loss of Emergency Coolant Recirculation, original ECA- LOCA Outside Containment, original FR- Response to Inadequate Core Cooling, original FR- Response to Degraded Core Cooling, original FR- Response to Imminent Pressurized Thermal Shock Conditions,
- original i-
'
E0P-3.1-10 Partial Loss of AC, Revision 9 E0P-3.1-50 Loss of MCC-5, Revision 1 '
i I
. _ _ _ _ _ . - _ _ _ . - _ _ _ _ . . _ _ . . _ _ . . -
_ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _
_ 40
.
B-2 ELECTRICAL DOCUMENTS B- Electrical Drawings 16103-3002 Main One Line Diagram 16103-3003 One Line Drawing 4160 Volt Bus 16103-3004 One Line Drawing MCC 4-1 and MCC 5-1 16103-3004-1 480 Volt One Line Drawing, BUS 4, 5, 6, 7 16103-3004-2 480 Volt One Line Drawing, MCC-1-1, MCC-2-1, MRR-3-1 16103-3004-4 480 Volt One Line Drawing, MCC 6,7,8 16103-3008 125 Volt DC One Line Drawing, BUS 1 and 2 16103-30011 4160 Volt One Size Drawing, Emergency Bus 8 and 9 16103-30012 4180 Volt AC-125 VAC One Line Drawing Emergency Generator l Distribution Cabinet EGG-2A and 2B 16103-30020 480 Volt One Line Drawing, MCC 9-4 and MCC 10-5 B- Preventive Maintenance Procedures (PMP)
PMP 9.5-16 50DHP-250 Breakers, Revision 8 PMB 9.5-17 DB-25 Breakers, Revision 11 PMP 9.5-50 DB-50 Breaker Procedures PMP 9.5-38 DB-75 Breakers, Revision 7 PMP 9.5-35 PM of Service Station Transformers 4160/480 Volt, Revision 8 PMP 9.8-7 4160 Volt Cable Insulation Test PMP 9.8-4 TestingType C0 Overcurrent Relays PMP 9.5-129 Performance Test of Station Batteries, Revision 2 PMP 9.5-136 Service Test of Station Batteries, Revision 2 B- Surveillance Procedures (SUR)
SUR 5.5-17 Quarterly Station Battery Checks, Revision 9 SUR 5.5-16 Weekly Station Battery Checks, Revision 10 B- Analysis Reports Analysis Report No. C2-517-618-RE, Revision 1, CY Emergency AC Power System FAULT Tree Analysis Analysis Report No. C2-517-624-RE, Revision 0, Recovery of AC Power .
at CY Analysis Report No. PA-78-741-01-GE, Revision 1, Diesel Generator Loading B- General Procedures Annunciator Response Procedure No. ANN 4.13-4 Abnormal Operating Procedure No. AOP 3.2--5, Revision 5
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B-3 . MECHANICAL DOCUMENTS B- P&ID's i
16103-26018 Sheet 1, Rev. 7'- Chemical & Volume Control, Letdown
, to Volume Control Tank, Sheet 2, Rev. 7 - CVCS - Purification-Sheet 3, Rev. 11 - CVCS - Boric Acid & Charging Lines Sheet 4, Rev. 3 - CVCS.- Return Liner to R.C. Loops and R.C.P. Seals 16103-26007 Sheet 1, Rev. 7 - Reactor Coolant System Sheet 2, Rev. 5 - RCS 16103 Rev. 26 - Safety Injection System 16103-26028 Rev. 7 - Residual Heat Removal System B- Documents NOP 2.1-1 Rev. 21, April 1,1987, Cold Shutdown to Hot Standby SUR 5.1-1 Rev. 31, April 12, 1986, Hydrostatic Test SUR 5.7-64 Rev. 3, No. 15, 1986, No Flow Test of Core Cooling Systems CMP 8.5-3 Rev. 11, May 26, 1986, Disconnecting and Reconnecting Electrical Connectors to Reactor Head Valve Spec. Sheet, PA #80-201, Rev. No. 0, 5/12/81 for MOV Drawing No. D-449665, Rockwell International, Cast Steel Horizontal &
Vertical Tilting Disk " heck Valve NEO 3.12, Rev. 3, April 25, 1986, Safety Evaluations SPL 10.7-273, Original, December 18, 1986, Residual Heat Removal Flow Test to Deter,mine FCV-796 Coller Dimensions Safety Evaluation for SPL 10.7-273, 12/17/86 Safety Evaluation Worksheet ISE/CY-86-104, 12/18/86
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B-5 INSTRUMENTATION AND CONTROL DOCUMENTS SUR 5/2-10, " Refueling Water Storage Tank Level Test", Rev. 5, Calibration performed:
4/10/87, 1/12/87, 10/15/87, 7/16/87, 12/17/85, 10/21/85, 7/19/85 SUR 5.2-26, Containment Sump Level Channel Calibration, Rev. 5, Calibration performed:
7/28/87, 1/18/86, Work Order CY 84-07330 SUR 5.2-52, Reactor Coolant Pressure Channel Calibration, Rev. 6, Calibration performed 12/19/86, 12/4/86, 12/1/86, 1/29/86, 4/19/86, 4/18/86 Temporary Procedure Change No.87-084, June 5, 1987, SUR 5.2-52, RCS Pressure Channel Calibration SUR 5.2-68, Refueling Water Storage Tank Level Instrumentation Calibration, Revision 3: Calibration perforn'ed:
3/9/87, 9/26/86, 3/20/86, 10/21/85, 4/10/87, 1/12/87, 7/16/86 l
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