IR 05000333/1988015
| ML20205J571 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 09/28/1988 |
| From: | Conner E, Eapen P, Moy D, Paolino R, Prividy L, James Trapp, Walker T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205J543 | List: |
| References | |
| 50-333-88-15, NUDOCS 8810310433 | |
| Download: ML20205J571 (53) | |
Text
m-.
~
,
.
i
U.S. NUCLEAR REGULATORY COMMISSION REGION I l Report N /88-15 Docket N l License No. OPR 59 _
Licensee: New York Power Authority !
P.O. Box 41 i Scriba, New York I Facility Name: James A. FitzPatrick Nuclear Power Plant f
Inspection At: Scriba, New York Inspection Conducted: August u 8-19, 1988 Inspectors: .
E. L. Conn r efect Engineer 9b4[W date D.T.MoyrRget
/ tw Engineer
+M ' dat'e ;
W I W R.'J.~ Paolino, S'enior Reactor Engineer h r- 9 /2r/97
'date
'
. .
L. J. trividy, Rean or Engineer hMfU date i
L
J. (b b rapp, ReactoF Engineer 9ho /ra
'date i
'
[~ML C.[ Walker,SeniorOperationsEngineer 4 /.2r/ss date (
i Approved by: N, k 9!1f [ [
Dr. P. K. Espen. 6 ef, Special Test / Hate i Programs Section, EB, DRS
,
I Inspection Sumary: Special Announced Probabilistic Risk Analysis (PRA) based j inspection on August 8-19, 1988, (Inspection Report No. 50-333/88-15). L
'
!
"/fa!Avd3 enc stf4B . !
- - - - . - - _ - - . . . - - _ . - - - - - _ - - - - - - - . - - - -
_-..?
,
.
-
.
.
-2-Areas Inspected: Reliability and availability of AC and DC power systems, diesel generators, emergency core cooling systems, service water system, air system, automatic depressurization system and main steam isolation valves; operation, surveillance and maintenance activities associated with the above systems; and personnel training, management and Quality Assurance overvie Results: In general the inspected systems were maintained at a high level of availabilit Senior management involvement, knowledgeable staff and efforts to track component history wer+. identified strengths. One deviation, failure to test HPCI suction flow path from the suppression pool (section 4.2.A); one violation, with three examples of failure to follow licensee's own procedure, failure to reconnect pipe support on RHR miniflow lines (section 4.4.),
unauthorized installation of hose clamps on RCIC turbine auxiliary lube oil sump (section 4.1) and inadequately dispositioned battery surveillance results (section 2.3.B); one unresolved item, root cause for causing the HPCI auxiliary lube oil pump pressure switch to become loose, (section 4.2.8); and one weakness, inadequate control of battery room environment (section 2.3.A); were identified.
s
.
. .
TABLE OF CONTENTS
.
TOPIC PAGE 1. Introduction, Inspection Methodology and Summary of Findings ........ 4 2. Electrical Systems .................................................. 9 3. Emergency Diesel Generators ........................................ 18 4. Emergency Core Cooling Systems ...................... .............. 25 5. Miscellaneous Systems............................................... 33 6 Integrated Plant Operations ........................................ 41 7. Licensee Personnel, First line Supervision, Senior Management and Quality Assurance Roles in Assuring Quality and Safety ......... 44 8. Unresolved Item .................................................... 46 9. Management Meetings.............. .................................. 47 Attachment 1 -- Persons Contacted Attachment 2 -- Documents Reviewed Figure 1 .......................................................... 5 _
..
.
DETAILS 1.0 Introduction, Inspection Methodology and Summary of Findings This inspection was conducted by a team of NRC personnel to review safety significant activities and equipment at the James FitzPatrick Nuclear Power Plant (JFNPP) . The system and accident sequences were selected using generic Boiling Water Reactor (BWR) Probabilistic Risk Assessment (PRA) insights and the experience gained from NRC inspections at other BWR facilitie Specifically, the inspectors reviewed the plant systems and operator actions that are required to prevent or mitigate the consequences of accidents that may resuit in core mel This section describes the methodology, the selected accident sequences and inspection areas and summary of findings; sections 2 through 7 describe in detail the inspection activities, findings and conclusion .1 Inspection Methodology The team prepared the basis for this inspection using generic BWR accident sequences that may result in core mel The selected generic sequences were reviewed for applicability to the JFNPP using plant specific design, operation and maintenance practices. From the above a final list of accident sequences, systems and components and human actions were selected for the inspectio The basic inspection rationale is depicted in Figure This rationale is used to evaluate the availability of selected components and the capability of plant staff to react to and recover from selected emergency situations. Although the inspection's primary focus was on "selected" components and activities, such programmatic aspects as management controls, oversight by quality assurance, training and human factors were also assesse The degree of equipment availability as supported by the performance records, programs, activities, initiatives, observed conditions, and apparent level of personnel competence was qualitatively evaluated based on the following criteria:
- measures to prevent equipment deficiencies or failures (preventive maintenance, trending performance);
- prompt detection of failures or deficiencies (surveillance);
- ef fective correction of such findings (corrective maintenance);
- verification of equipment operability (post-maintenance testing, calibration, and operation check-off).
- _ ._ .. ._ - _ _ _ ._ _ _ _ _ . ._ _- - - _ _ . - - .. . _ _ . _ _ -
.
. .
,
PmA o* ' sensesmesmos of HIGH ASSURANCE seemer me,enemms OF *
- sesmatosts OPERATIONAL READINESS * " " " " " "
, e STAFF ACTWts
.
ca. Pisae Egr W I A,-send?
'
m-I I I I Anemos Aseeme Aenene Headware Heedusase Adminieeredue
--_:--, c- -
Comere Plant Aamens Senft N Coe Phas
_
semeram w9 l
Ll
1 3.rweemence/Cohe&en E- ^Mb ^^ ^ ~~
tr'ien't Womeewoughel ' b 8' A'**"*
t:-
Sweemm As Found '
l Unmempo P- h
.. - Comminamme y,,,,,,,,
, -
ume .e ..
!
,
w '
! Procedure TA h hearing 8'*'"*8# "*'
--
--r as
=-
-- e ""'8"'"
!
.
i.e. e- a.ePe e-e Potomalmi
'T r p e. i l Cesasmen Comme
,,e.e.,,m,,.e,c _ remm smand c_ _
. _
_ m Hum'**
!
!
!
.
t, %.
.i
- Feisure Femurg, Post -'
- - _ :e Poesept/Efsesteve Prowesse6ea Tresseng .
i TeseenetAsseeestsose Coevesasen er E= onensemanees seummmen o-enacaen oA 8aee8==== mat
) Peres Repamemament l
Figure 1 - Rationale of PRA Driven inspections
.
i
. . - . . - .. . . - . -.. .. .
- . . - _ . - . _ . .. . . -_
.
.-
-6-
.
Procedures were walked through with qualified personnel in the control room, at the switchyard, and in equipment areas. Operations were evaluated to ascertain that operators were familiar with the plant equipment and the associated plant procedures during normal, abnormal, and emergency situations. The event simulations were evaluated to determine 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 remotel The procedures were evaluated for adequacy, technical accuracy, clarity, and consistenc .2 Selection of Accident Scenarios and Inspection Areas The events listed below were selected as the focus of the inspectio Various combinations of these events were used to simulate accident scenarios that would lead to core melt. Generic probabilistic risk assessment insights for BWRs were used and modified to licensee plant specifics, to select these accident scenarios with the greatest core melt probabilit Loss of Offsite Power concurrent with a Turbine Trip;
-
Loss of All AC Power (Failure of the Emergency Diesel Generators);
-
Failure of a Saf-ty Relief Valve;
-
Failure of the Reactor Core Isolation Cooling System;
-
Failure of the High Pressure Coolant Injection System;
-
Loss of DC Power;
-
Failure to Depressurize the Primary System (via SRVs or A05).
The above events were used to determine the systems and their related potential equipment f ailures, procedures, and human f actors aspects for inspectio The inspection included a walk through of the tested events and recovery actions with operations personne .3 Summary of Findings
- A. Str_engths In general, this inspection indicated good initiatives by the licensee to maintain a very high level of availability for those systems, structures and components that are required to prevent or mitigate the consequences of core melt. The licensee management appeared to be responsive to recent assessments by the NRC and INPO and instituted slow but deliberate corrective actions to improve reliability and availabilit The programs established so far, provided excellent availability for systems reviewed during this inspectio The licensee has established reasonable goals in
.
..
-7-
.
all functional areas and does a credible job in tracking and informing personnel about the status. The plant departments were highly self critical and were aware of areas needing improvement. Quality Assurance (QA) was recognized and utilized by the licensee as an effective management tool in specific assessment, feedback and corrective action processes. This is in addition to the routine QA inspection, surveillance and audit responsibi-litie The following strengths were noted in particular:
(1) Senior Management Involvement Senior licensee management (both corporate and site) is actively involved in assuring a high availability and reliability for plant system The management initiatives to establish design basis documentation and to develop a plant specific probabilistic risk analysis (PRA) were progressing effectively at the time of this inspectio The initiative to develop a detailed PRA that is readily useable for the site, operation, maintenance and modification activities, by 1991, is an example of strong management involvement in the PRA are (2) Knowledge of Personnel The licensee's operations, maintenance and technical personnel involved in this inspection were highly knowledgeable in their respective areas and responsibilitie The licensee took initiatives to obtain accreditation in all training programs thct are being accredited by INP0. At the time of this inspection, the licensee was completing the installation of a plant specific simulator. The licensee also established an apprentice program to provide its mechanics and technicians on-the-job training. These initiatives add to the reliability and availability of plant systems by minimizing down time and personnel error (3) Plant Equipment Performance Tracking The licensee has developed a performance tracking system for safety related components. This performance tracking system will be used in the formation of the PRA and will be used for scheduling of preventive mainte-nance activitie (4) High Availability for Systems The licensee has maintained high availability for systems reviewed during
, this inspectio The following table provides the estimated average availability for these systems from 1986 to the presen The estimated availability was calculated using the time that the system was required to be operable by Technical Specifications and the time that the system was inoperable when require ,
- - - - - _ _ _ - . _ _ _ _ _ _ _ _
C e -
-8-
.
System Availability (%)
- HPCI 98.55
- RCIC 99.21
- ESW 99.92
- EDG 99.93
- RHR/SW 99.69
- OFFSITE POWER 100.00 B. Deviation One deviation was identified from FSAR Section 6.6 commitment to ensure proper operation of the valves and strainers in the suction flow path when the HPCI pump takes suction from the suppression pool. The licensee had no steps in the operation or surveillance procedures for HPCI flow path verificatio This deviation is significant from a risk point of view, as the licensee did not periodically test a flow path that is required to mitigate the consequence of an accident leading to a core melt. Upon identification of this deviation, the licensee developed a test procedure to verify the flow when the HPCI pump tckes suction from the suppression pool. The test was successfully conducted on August 19, 1988 (section 4.2. A for details).
C. Violation Several examples of failure to follow the licensee's own procedures were note (1) The licensee's work request, No. 54981, to remove pipe support H10-63 and H10-74C on the RHR miniflow lines, states "temporarily disconnect existing pipe support to permit power brushing of the piping and reconnect immediately thereaf ter." However, the above supports were disconnected in January of 1988 and were not reconnected until August 1988, when identified oy the inspector. The licensee immediately declared the RHR system inoperable and entered a seven day Limiting Condition of Operation (LCO) as required by Technical Specifications until the supports were reconnected. The licensee also performed an analysis to assure the adequacy of the miniflow line without the above supports. The preliminary results indicated that the stresses were well within ASME code allowables at all points of the piping v system (see section 4.4 for details).
(2) An unauthorized installation of hose clamps was observed at the auxiliary lube oil sump associated with the Reactor Core Isolation Cooling (RCIC) turbine (see section 4.1.).
(3) Weekly surveillance test procedures for LPCI IPS, 125V and 24V batteries (MP-71.10, MP-71.12 and MP-71.14) require that if the pilot cell electrolyte temperature exceeds 90'F and does not exceed 110*F
.
..
_ .
(120 F for 24V) to classify the test as satisfactory with required corrective action block checked. However, the surveillance test results for July 13, 20, 27 and August 3, 1988, indicated that when the electrolyte temperature exceeded 90 F, the tests were accepted as satisfactory without checking the corrective action required block (see section 2.3.A).
In addition, to the above examples, Section 3 and Section 4.1 of this report discuss further observations indicating inadequate work control procedure D. Weakness The reliability of the battery room ventilation systems was noted as a weak area in the licensee's operation. This is based on a combin& tion of facts.rs which include numerous inoperable components, unavailability of replacement parts, potential design inadequacies and lack of monitoring and procedural guidance for the LPCI IPS batterie Hydrogen buildup, low ambient temperatures, or high ambient temperatures, resulting from failure of the battery room ventilation systems, have the potential to affect the availability of the batteries when neede This potential makes this weakness significant from a risk perspective (see section 2.3.A).
E. Unresolved Itrm An unresolved item was identified to address the root cause associated with the loose mounting of the pressure switch for the HPCI turbine auxiliary lube oil pump (see section 4.2.B).
With the exception of the above deviation, violation, weakness and unresolved item, the team found plant equipment, procedures and personnel actions to be conducive to maintaining a high level of availability for systems reviewed during this inspection. The foregoing, while having potential to ef fect system availabilities, were judged by the team as isolated instances and not Indicative of practices throughout the facilit The existing practices, procedures and personnei actions in all areas were observed to be contributing positively to system availability. There are also sufficient management controls in place to identify and correct problems and weaknesses in a prompt and effective manne .0 _ Electrical Systems 2.1 Off-Site Power The major contributor to overall station blackout risk is the likelihood of losing of f-site power and the duration of power unavailabilit .
..
-10-
.
A review of the New York Power Authority's existing facilities indicate interconnection with other utilities and with major load centers with transmission lines consisting of one 765 kV line, two single circuit 345 kV lines, two double circuit 345 kV lines or combination of single circuit 345 kV, 230kV and single and double circuit 115 kV line on the same right-of-way. The 345 kV line between the JFNPP and the Scriba Substation are protected by 345 kV air-blast circuit breaker During normal operation all breakers in both switchyards are closed and all lines energize In the event that both lines could be out of service simultaneously, the event would not jeopardize the safe shutdown of the plan In the event of a load reject, opening of the Turbine Bypass Valves permits the turbine generator to continue to run and carry the load of the plant auxiliaries. With a load reject greater than the capacity of the Turbine Bypass Valves, the reactor trips and automatic transfer of plant auxi'iiaries to the 115 kV bus result Disconnect switches in the 345 kV switchyard include motor operated breaker isolation switches located on each side of the 345 kV circuit breaker, and one mctor operated switch in the tie between the main step-up transformer and the 345 kV bus. These switches are powered from separate 125V DC power sources that are physically separated. All breakers and disconnect switches have control switch and status indication lights in the control room. Each 345 kV circuit breaker and disconnect switch can be operated by the control room operator. Circuit interlocks ensure that all prior required action is performed prior to manual operation of any switch or circuit breake The two 115 kV transmission lines to the plant are protected by 115 kV oil circuit breakers. During normal operation both circuit breakers and all disconnect switches are closed and each line is energized. Each circuit breaker has two trip coils either of which can trip the breaker. Separate 125V DC power sources are used for each trip coil and its associated tripping contact Electrically operated disconnect switches in the 115 kV switchyard include a bus sectionalizing switch and a disconnect switch between the bus and each reserve station service transforme Separate 125 V DC power sources are used to control the switche Each circuit breaker and electrically operated disconnect switch has control switches and status indication in the control room. Circuit
. interlocks are provided to prevent accidental operation of the circuit breaker or disconnect switc The JFNPP is normally disconnected from the 115 kV system since the normally open position of the 4 kV circuit breakers are connected to the low voltage side of each reserve station service transformer. In addition, the disconnect switches can be opened to completely uncouple JFNPP from the 115 kV transmission system. These switches cannot be opened unless either of the 4 kV or 115 kV circuit breakers are opened. Operation of
.
..
-11-
.
both the JFNPP and Nine Mile Point Nuclear Station (NMPNS) facility is coordinated so that the reliability of one station is not jeopardized by operations in the other statio In addition, transient stability studies were performed by the licensee to examine the interconnected transmission system of JFNPP and NMPNS. The tests based on 1985 conditions were performed in conformance with tA criteria outlined in the NMPNS document entitled "Basic Criteria for olgn and Operation of Interconnected Power Systems". The results of tb.6e studies indicate that:
- If a fault occurs on tha 345 kV transmission system in New York State, the two 115 KV power sources for plant auxiliary equipment from Lighthouse Hill and Oswego would not be interrupted. Generator units at JFNPP and NMPNS as well as other units in the interconnected system would remai, stabl *
If the fault occurs on the 115 kV transmission the JFNPP remains stable and the associated 345 kV transmission will not be affecte * Direct tripping of the JFNPP, as a result of a fault on the 345 kV system will not open the 115 kV auxiliary power lines or disrupt the 4 kV station service lin * The 345 kV transmission and the two 115 kV source of auxiliary power supply are not affected by the loss of NMPNS which is considered as the most critical unit in the New York Power Poo The effect resulting from a loss of Indian Point Unit 3, the largest unit in the New York Power Pool is less severe on JFNPP st ibilit The licensee's availability record indicated that the above off-site powe" supply scheme enabled the licensee to maintain overall off-site powe; availability at one hundred percen Tne inspector concluded that there are sufficient off-site power sources through interconrection with other systems and safeguards to minimize the station blackout risk from off-site power source ,2 Plant A_C Distribution Systems The JFNPP AC distribution systems consists of normal, reserve and emergency AC power sources, the Plant Service AC Power Distribution System, the the 120 VAC Power System, and the 600V Motor Operated Valves
,.., AC/DC Inverter Syste The normal AC power source provides AC power to all plant auxiliaries and is the source of power when the main generator is operating. The reserve AC power source provides AC power to plant auxiliaries and is in use when the normal AC power source is unavailable. Power is provid(d by two transformers connected to the 115 kV bu Each transformer can provide the power requirer.ents for one half of the plant auxiliarie .
..
-12-
.
The emergency AC power source provides AC power to :uxiliaries required for safe shutdown in the event that neither the normal or reserve AC power is available. The power source for the emergency AC power system consists of two diesel generators operated in parallel. Each source has sufficient capacity to safely shutdown the reactor and ma'ntain the reactor in a safe shutdown condition, aad operate all the auxi'aiaries necessary for plant safety. The Plant Service AC Power Distributior. Systems distributes all AC power necessary for startup, operation and shutdown of the plan Power for all buses ir, this system is from the normal or reserve AC power sourc The 600V AC Power System provides reliable on-site power through AC inverters and 480V DC battery units to the LPCI system motor operated valve The nsp.mtor concluded that p.1ytical separation in the Plant AC Distrie. tion Systems between similar redundant components is adequate and that loads important to safety are s;. it and diveraified between power buse .3 OC Distribution and Battery Systems The purpose of the DC Distribution and es ttery System is to supply all normal and emergency loads for the DC puwered components. ?n the case of a loss of all AC power (Station Blackout), the DC battery systems are required to supply power to safety coaconents and systems for accident mitigation and safe shutdown of the plan The DC systems also supply essential monitoring and indicating function Tnere are three major DC Distribution and Battery systems, 125V; 24V; and LPCI Independent Power Supply (LPCI IPS).
The 125V DC Power System (station batteries) consists of two separate i.id independent systems, each consisting of a 58-cell battery a t c>t'ery charge The battery chargers are supplied from separate 60s"i eergency buses and normally supply the 125V DC loads whilt maintaining the batteries in a fully charged stat The battery charger and control board are in a separate room from the batte , (DC Equipment Room). The battery room ventilation system consists of one Air .iardling Unit (AHU), two exhaust fans, and one recirculation fan for each battery system. Inlet air is heated by glycol heatiig , 's and recirculated in the DC equipment rooms to maintain supply air .w m ture above 60 degrees F. No system
~.< cooling is provided, but the vei..<'stion system is designed to start automatically if room temperature reae.hes 110 degrees The 24V DC Power System provides powar to neutron moa: coring instrumenta-tion and process radiation monitoring instrumentatio The system consists of two 100*; capacity 2?V OC sources. Each source consists of two 12-cell batteries and two battery charger The system components are located in the same locations as the respective 125V components.
-
_ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
0 *
-13-
The LPCI IPS provides an independent power source to vital MOVs in the LPCI and Reactor Water Recirculation (RWR) systems. The system is comprised of two seoarate and indep" dent 419V DC power supplies, each consisting of a 186-cell battery, a bat.ory charger and an inverter. Each battery is in a separate room with ventilation supplied from the Reactor Building Ventila-tion and Cooling System. Each battery charger and associated inverter is located in a single steel enclosure with a separate HVAC system designed to protect the equipment from .he harsh environment resulting from a high energy line break in the Reactor Buildin A. Battery Room Environment
_
The inspectors performed walkdowns of all the battery rooms and DC equip-ment room During these walkdowns it was noted that ambient temperatures were elevated (approximately 95 to 100 degrees F) and that air circulation was minimal. Deficiency tags were noted on several ventilation system instrumentation and monitoring components. Nonexplosion proof light switches and fluorescent light starters were observed in both the station battery and LPCI battery room (1) Hydrogen Buildup One area of concern is the adec.uacy of the batcery room ventilation systems to eliminate hydrogen buildup. The ventilation systems are designed to maintain less than two percent hydrogen concentration during the highest postulated production period based on providing continuous exhaust at a flow rate sufficient to recycle the air in the battery room The station battery rooms are equipped with two exhaust fans in each room. One fan is running t all times, with the second fan in standby, The second fan will auto start if the running fan fails and an annunciator provides indication of ventilation system trouble in the control room. Flow switches in the exhaust fan intakes provide the auto start and annunciator signals. Similar flow switches in the recirculation fan intake lines were found to be deficient in January and February 1988 and have not been repaired to date due to unavail-ability of replacement parts (since 3/1/88 when calibration of the switches was attempted).
The LFCI battery rooms are also equipped with redundant exhaust fans
, that operate in the same configuration as the station battery room exhaust f ans, except there is no annunciacion in the control room to indicate a failure in LPCI battery room ventilation. The ventilation system in the LpCI battery rooms is monitored locally once per shif t during nperator round .
.. .
-14-
.
(2) Temperature Control The adequacy and reliability of the battery room ventilation systems to maintain a temperature controlled environment for optimum battery performance is an additional concern. Battery performance is dependent upon the temperature of the battery electrolyte. Nominal battery operating temperature is 77 degrees F. Lower battery temperatures decrease the capacity of the batteries (90% capacity at .
60 degrees F). Higher battery temperatures increase battery '
capacity, but decrease battery life. The vendor for the station batteries specifies that temperatures up to 110 degrees F are acceptable. High ambient temperatures are also a concern for operation of equipment other than the batteries (i.e., battery chargers).
The inspectors observed performance of the weekly surveillances on ;
the 125V, 24V and LPCI IPS batteries. Electrolyte temperatures on all of the batteries were above 90 degrees . The surveillance procedures require that if electrolyte temperatures exceed 90 degrees F, but do not exceed 110 degrees F (120 degrees F for 24V), the test be classified as satisfactory with required corrective action, i Review of the weekly surveillance results for 1988, that had gone through the licensee's complete review cycle, revealed a procedural violation. In the single case where electrolyte temperatures had exceeded 90 degrees F, the test results had been dispositioned as satisfactory with no correctiva actior, required. Afte- the error was identified to the licensee, review of all weekly batter, surveillance tests performed to date was complete Eight additional cases of incorrect disposition of surveillance results were identified and correcte In all cases where temperatures exceeded 90 degrees F and the results were reviewed prior to identification of the error by the NRC, the results had been incorrectly dispositioned. This constitutes an example of a violation of Technical Specific) tion 6.8.(A) which requires implementation of established procedures (50-333/88-15-01).
)
Review of the weekly surveillance results indicated that electrolyte !
temperatures had been in excess of 90 degrees F for all 3 battery systems since July 13, 1988. The vendor specifies that normal l battery life can be expected only when the batteries are operated at e an annual averege tersperature of 77 degrees F and cell temperatures do not exceed 90 degrees F for more than 30 days per year. In July ;
1986, a cell in the ' A' LPCI battery exceeded 90 degrees F. The licensee performed a study to determine compliance with the manufacturer's requirements. Battery temperatures were monitored for eight weeks and yearly temperature averages were calculated. No :
corrective action was recommended at the time. In response to the recent high electrolyt9 temperatures, the licensee agreed ta monitor and evaluate the effect of high temperatures on the batterie _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ -
.
. .
-15- '
i
.
For the duration of the inspectiti, ambient temperatures in all the '
battery rooms were approximately 100 degrees F. Temperatures in excess of 118 degrees F were measured on contact with one of the station battery chargers.
The inspectors noted that the temperature switches that provide an auto start of the AHU and recirculation fan and a high-high tempera-ture alarm at 110 degrees F, had not been calibrated since May 14, 1973. The temperature switches had been designated vs Category II components until a recent revision of the Master Equipment List (MEL)
which upgraded them to Category I. All other temperature and i differential pressure switches associated with the battery room !
ventilation system are calibrated once/ cycle as required by Technical l Specifications. The high-high temperature switches are not required to be calibrated by Tech Specs because they have no associated temperature transmitters. The inspectors observed the calibration of these temperature switches. One of the switches did not trip with temperatures in excess of 250 degrees F. The other switch tripped at 119 degrees F but could not be calibrated. Replacement switches were not available and were expected to be received in approximately five weeks. With both switches inoperable, no automatic start of the AHU
.
i and no remote annunciation of temperatures above 110 F were available.
, The temperature controllers that maintain system air inlet tempera-ture by operation of dampers and glycol heating have been inoperable i since April 29, 1983 and jumpers are installed to block open motor j
operated dampers to supply outside air to the battery rooms. One of ,
'
, the controllers requires a new transistor and has not been repaired due to unavailability of parts. The other controller was not operating properly due to inoperable motors on both of the motor operated dampers that it control Replacement motors ara not available and a modification is required to restore the components to i operability. W!th both temperature controllers inoperable, no '
automatic method of controlling ambient temperature above 60'F was ;
available.
LPOI battery room ventilation is not specifically addressed in ,
Technical Specifications and therefore does not appear to be given '
,
the same level of attention as the station oatter, environmen ,
There is no temperature monitoring instrumentation available in the
'
I'
'
LPCI battery rooms and no annunciation provided locally or in the control room for ambient temperature. Ambient temperature and proper
,
operation of the ventilation system is checked once per shift during i
+
operator rounos, but no acceptance criteria are specified in !
procedures or checklists and the operator must use his or her ,
judgement as to whether ambient temperature is satisfactor The LpCI batteries are similar in design to the station batteries and have comparable operational limits specified by the vendo Individually, the above deficiencies are of minimal concern; however, collectively these indicate a weakness in the control of the battery room L environment.
-
. _ _ _ , _ _ . . _ _ . . _ _
, . . , . - _ , _ . . . _ _ _ _ _ . _ . - _ _ , . _ _ _ _ , .
_
, . , . _ , - __ _ _ _ , , , _ _ . . . , ,
___ ____ ________ _______ _____ __________ _ __-___ __________-_ __
.
r
. .
-16-
.
B. 125V DC Battery Duty Cycle The inspector reviewed licensee calculation number EDA-JFNPP-87-801 dated
.'
September 2, 1987 for updating Battery Design Duty Cycle calculation number E-74 dated September 27, 1974.
4 The licensee baset "Outy Cycle" on a loss of coolant accident which initiates the High Pressure Coolant Injection (HPCI) and the Reactor Core !
Isolation Cooling (RCIC) systems and the simultaneous loss of all available ,
AC powe [
The assumption is made that during the "two hour duty cycle" no AC power is available for the entire period. Unknown locked rotor currents are assumed to be 10 times full load currents for DC motors without reduced voltage starting, and 25 times full load current for DC motors with reduced voltage starting. DC motor starting currents are based on battery control board voltage of 115V and DC motor control center voltage of 110 The inspector concluded that the licensee's battery duty cycle estimates
-
were conservative and it indicated sufficient margin for DC starting t loads.
.
C. Conclusion
, The results of the inspection indicate that the DC Distribution and Battery
systems are designed to provide DC power in a reliable manner. However, the battery room environment issues discussed above could have a detri-mental effect on battery availability. Maintenance and surveillance of the battery systems are adequate to assure continued reliability. However, detrimental environmental factors could reduce the capability of the batteries to perform their intended functio The numerous inoperable components, the unavailability of replacement parts, and the lack of -
monitoring and procedural guidance for the LPCI batteries contribute adversely to the reliability of the battery room ventilation system ;
Upon identification of the concerns by the inspectors, the licensee took i actions to calibrate the high-high temperature switches and to monitor and -
evaluate the high electrolyte temperature .4 Switchyard Alarm Response Procedures Walk Through
, The 345kV and 115kV systems raquire routine inspection of the air breaker I and SF6 gas systems and of oil 'evel. These routine inspections are !
performed by maintenance personnel. Procedure F-0P-45, section l requires that breaker air system alarms in the control room must be checked immediate'.y as rapid air loss will disable automatic breaker l trip In order to determine operations personnel ability to assess switchyard conditions, the inspectors accompanied a licensed reactor operator on a walk-through of several alarm response procedures that require investigation and recovery actions to be performed in the switchyar I
.
i
-
17-
\
The operator was familiar with the location of the cabinets that contain air and SF6 gas instrumentation and equipment, but was unfamiliar with the
, location of instruments and valves within the cabinets. A diagram of the SF6 system was provided in the alarm response procedure and inside the cabinet to assist the operator. This diagram was not adequately labeled to enable the operator to locate the equipment. Assistance was provided from an electrician who was very familiar with the equipmen ;
Several deficiencies in the alarm response procedures were identified as a result of the walk through. The procedure for response to low air pressure ur loss of AC power to 115kV breakers did not provide setpoints which would assist the operator in identifying the cause of the alar The procedure for response to air or SF6 gas problems for the 345kV breakers contained precautions concerning SF6 gas addition at certain temperatures after the steps that direct SF6 gas addition. These '
deficiencies were identified to the licensee and corrected by procedure ,
change !
The inspector concluded that, following the implementation of the identified procedure changes, the licensee's alarm response to procedures are adequate to restore components in the switchyard. The equipment familiarity concern discussed above was identified to the license The licensee acknowledged this concern and agreed to review this matter to determine whether this is an individual or generic deficienc .5 345 kV Backfeed On Loss of 115 kV and Emergency Diesel Generators Ir. a simulated loss of 115 kV and Diesel Generators, the inspector ,
observed the licensee's activities to restore power by backfeeding the .
345 k The Maintenance Procedure used was number MP-71.2, Revision 0, dated March 12, 198 The stated purpose of the procedure is to detail the method used to isolate the generator output terminals from the "isolated phase bus".
The mechanical separation of the generator from the isolated phase bus will enable the normal station service transformer T4 to be backfed from ,
the 345 kV systems without energizing the generator. The procedure also will enable the separation of these components in the event either needs to be tested independentl Special tools required to perform the task are the hydraulic power lift r to reach the isolated phase bus and portable hand held light Licensee personnel simulated protective tagging and grounding procedures prior to initiating the equipment opening and removal of 96 bolts to gain access to the four links in each phase compartment to the bus for removal of link Licensee personnel stated that the process took approximately I four hours to complete during a previous attemp '
i
-
P 4 -- -- m-,- - - - - -
. , - - - - - -4,-. -- . , . , , , , . - , - ,y v--. . ,,,
_ _ _ _ _ _ . . _ _ _ _ _ _ _ _
.
. -
-18-
.
This method can be used during plant outages when it is necessary to remove the 115 kV system from service or to use 345 kV as an alternate power supply in case of a station blackou In addition, components powered from the 10700 bus, which is not powered from the 115 kV system reserve power would be available while backfeeding from the 345 kV syste Based on the above the inspectors concluded that the licensee's procedure to backfeed the 345 kV provides an adequate means of restoring power during a loss of off-site power and diesel generator .0 On-Site Emergency AC Power Supply / Emergency Diesel Generators A loss of off-site power in conjunction with failure of the emergency diesel generators (EDGs), was identified as the initiating event in tha selected PRA accident sequence (see Section 1.2). This event could rt> ult from a common mode failure of the operable EDG pair while other EDGs are out for maintenance. Therefore, the inspector examined various aspects of the EDG system including potential common mode failures and failures of support sub-systems including faulty maintenance and surveillance which could trigger a failure of the diesels or generator In addition, component failure histories and recent and planed modifications were reviewe The possible failures of the electrical power distribution buses and related failure aspects are addressed in Section 2 of this repor .1 Uesign Review The FitzPatrick emergency AC power supply includes four emergency diesel generators (EDGs) operating in pairs to supply two emergency AC power buses. Normal AC power for the emergency buses is supplied from the main generator through the unit transforcer Reserve AC power for the emergency buses is supplied from the switchyard through the station transformers. For more dettil, see Section Each of the AC generators has a continuous rating of 2,600 kW and each diesel engine has a continuous horsepower rating of 3,600 hp. The EDGs may be manually started from the control room or from the EDG switchgear rooms. They are automatically started in the event of a emergency bus fault or detection of a loss of coolant accident (LOCA). The EDGs are designed to reach rated frequency and voltage within 10 second The r modes of emergency operation are as follows:
- Upon detection of bus undervoltage (less than 2975 volts for seconds) or degraded voltage (less than 3780 volts for 9 seconds),
both EDGs for the bus are automatically started. At approximately 200 rpm, the EDG tie breaker for the associated EDGs is automatically closed. At approximately 400 rpm, the fields of both EDGs are auto-matically energized from the 125 volt plant DC power sources and a start signal is sent to the associated emergency service water (ESW)
l l
[
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _
.
. .
-19-
.
,
pum The paralleled pair of EDG units continue accelerating to full speed. If the voltage on the emergency bus is below normal at the instant the associated pair of EDGs attains rated frequency and voltage, the supply for normal and reserve power to the bus and all feeder breakers, except the supply breaker to the 600 volt AC ,
i emergency buses, are tripped open. The EDG output breakers are closed, subsequently opening the associated tie breake * Upon detection of a LOCA (low-low reactor water level or high drywell pressure), all four EDGs receive a start signal whether or not reserve AC power is available. The startup sequence is the same as that for the loss of bus voltage (above) except that the EDG output breakers are closed only if the associated bus is not energize ECCS loads are then automatically sequenced onto the bu If either EDG in a pair fails to start in response to an automatic start signal, closure of the tie breaker is inhibited during the startup sequenc If LOCA conditions exist and one diesel fails in a pair to start, the second RHR pump does not receive a start signa EDG protection is provided by; four generator trips (differential, phase ,
fault overcurrent, loss of field, and reverse power), an engine overspeed '
trip, a low lube oil pressure trip, and a high jacket water temperature tri The low lube oil pressure and high Jacket water temperature EDG trips are blocked when LOCA conditions exist. If the EDGs are supplying emergency bus loads and one of the units fail such that it is being motorized by its companion unit, then the reverse power relay will trip the failed EDG before the companion EDG trips on overload. The overcurrent relays are set so they do not trip the generator on transient
! overcurrents or surges in power due to starting or tripping of large load The EDG supporting sub-systems are DC Control, Starting Air Fuel Oil, ,
Lube Oil and Cooling Water Syste The team concludes that the FitzPatrick emergency power system with i two independent electrical buses each supplied by two separate EDGs, i
although complex, is reliabl This is based on the ability of one EDG to supply the bus' emergency loads, with the exception of one RHR pum Therefore, this design has an installed spare EDG per redundant emergency ba The licensee indicated that they are 4,.. involved with a progra.n to show that one EDG per emergency power supply is adequate. This would require changes in the EDG and electrical distribution control logic, but could further improve reliabilit !
,
3.2 Technical Specification Requirements t The Technical Specifications (TS) require monthly demonstration of each pair of EDGs to start, accelerate, force parallel and operate at 5,200 KW I (2,600 KW each) until both ED3s are at steady state temperature cordition l
)
i
_ _ _ _ _ - . _ _ __ _ __ -
_ _ -_ _ - _ ._ ._ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ . _ _ _ - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _
.
..
-20-
.
Sub-system components such as the starting air compressors, system instrumentation, and diesel fuel quantity and quality also require monthly surveillances. Once each operating cycle, the EOG pairs must go through a -
simulated demonstration to start, accelerate, force parallel, and accept the emergency loads in the prescribed sequence. The safety analysis assumes each EDG will attain rated frequency and voltage within 10 second A total of 64,000 gallons of fuel is required for EDG operability. The !
inspector verfied by a review of test procedures that TS surveillance requirements were implemented during plant surveillance testin No problems were identifie .3 Maintenance The inspector reviewed maintenance procedure MP-52.9, Preventive Mechanical Maintenance for Diesel Engine and Auxiliaries, Rev. 2, dated August 4, 1988. Discussions were held with the author and assigned EDG 1ead engineer. This new procedure requires the inspection of the engine and adjustment of exhaust valves, injectors, and fuel racks. The testing section requires EDG operation for a mir.imum of one-half hour while maintenance personnel inspect the unit. The procedure has detailed instructions including visual aids, inspection checksheet, record sheet for new parts, and other data sheet Maintenance procedure MP-52.10. Electrical Preventive Maintenance for Diesel Engine and Auxiliaries, was also reviewed. This procedure covers generator component inspections and preventive actions to extend EDG lif Appropriate sign-off spaces for the electrician and for quality control representatives are include The inspector reviewed the other MP-52 series mechanical maintenance procedures, a number of which have recently been revised. Use of these procedures should have a positive effect on EDG reliability. Copies of all completed EDG inspections are sent to the lead engineer for his review and evaluatio Both preventive maintenance procedures, MP-52.9 and HP-52.10, have precautions stating that, "The engine should not be restarted between 15 minutes and 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> following an engine shutdown." This precaution comes from a 1980 Maintenance Instruction, MI-9644, from the EDG manufacture Restarting a diesel engine prior to unit cooldown could cause abnormal wear to the turbocharger bearings during high speed emergency starts.
,. This is due to an unbalanced lube oil flow when the viscosity of the oil is lower than normal. lhe licensee plans to implement a modification which will eliminate the above precaution (see Section 3.5, below).
Work Requests for equipment repair and/or replacement during the August 1988 refueling outage were reviewed. Starting air motors, ball check valves, and oilers in the starting air sub-system and fuel oil, lube oil and air filters in their sub-systems have been put on a routine replace-ment schedule. In addition, oil leak repairs, tank and heat exchanger
________ _ - _ _ _ ____- _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _____
.
..
-21-
.
inspections, and other miscellareous work will be performed. ECG engine
"A" will be rebuilt by replacing its cylinder power assemblies during the outage. This is the first complete engine overhaul at JFNPP. These types of preventive maintenance are expected to maintain and/or improve EDG reliability.
'
A number of examples of good maintenance planning practices were observe System components suco as the starting air compressors, various fuel oil parts, and other Oging items have been replaced or rebuilt, or are scheduled to be repaired during the upcoming refueling outage. Component repairs and/or replacements are logged on a sketch of each engine by the assigned system enginee .4 Surveillance i
' The inspector witnessed licensee performance of monthly operational surveillance test F-ST-98, EDG Full Load Test and ESW Pump Operability
'
I all EDG support systems such as AC and DC distribution, instrument calibration and operability, cooling water compor.ents, starting air equip-ment condition, fuel oil operating condition, and engine lube oil operability. The test and data collection perfr.rmed on August 18 was acceptabl However, the inspector noted two concerns in F-ST-98. Upon completion of the test of EDGs A and C, the procedure specifies the allowance of four hours for cooldown of EDG A and C prior to testing EDG B and D,
"
but does not return the system to normal. This leaves the A ESW pump running and EDGs A and C unprepared for standby operation. Also, the
instructions for returning EDGs to standby operation are not in the surveillance procedure. The operator must refer to the oper ating procedure, F-0P-22. The inspector discussed this with a Shift Supervisor and later received a draf t copy of Rev. 24 to F-ST-9 Both of the concerns were
'
adequately addressed in this revision. The inspector had no further questions regarding this matte During surveillance test F-ST-9B, the inspector observed the operation of 1 the EDG room ventilation system. Both "A" and "C" EDG room supply fans started and the exhaust dampers opened when the diesels started. The
! proper operation of the ventilation system was not verified as a part of i
the monthly EDG surveillance tes The licensee committed to incorporate the verification of ventilation system operation into the surveillance program, w
The inspector accompanied the auxiliary operator (AO) during the daily rounds. The inspector noted that the A0 only blew down ene starting air accumulator per accumulator set. Thus, only two of the ten accumulators per EDG room were blown down. One purpose of this blowdown is to check the auto start of each compressor. Another purpose, according to the EDG mechanical lead engineer and an operations Shif t Supervisor, is to remove
_ _ _ _ - _ - _ _ - _ _ - _ _ - - _ _ _ _ _ _ _ _ _ - _ _ _ . _ _ _ _ _ _ _ _ - _____ .
.
.-
-22-
.
condensate from the air tanks. The wording on the AO's check sheet is
"Drain Cond. & 011 from Air Tanks". After the inspector questioned the AO, blow down of other accumulators was performed. The licensee committed to issue a standing order clarifying the intent of air tank blowdown and -
later to improve the A0 checksheet or, this poin t Changes in the physical parameters of the fuel oil (FO) and the lube oil ,
(LO) provide important information regarding EDG operation. In accordance [
with TS, the licensee has the F0 analyzed on a monthly basis. Data reviewed '
showed that the flash point, pour point, viscosity, water, and impurities were within requirements. Analysis of the lube oil is performed by a contract specialist on a quarterly basis using the recommendations of the EDG service company. The LO reports showing metal impurities, F0, water, solids, viscosity, flash point, etc. were also reviewe The LO is normally replaced every two years. The F0 and L0 analyses and the routine L0 changes contribute to EDG reliabilit .5 Modifications The inspector reviewed the following planned modifications to the EDGs for l the September 1988 refueling outag Upgrade of the EDG Speed Switches, MOD F1-87-079, Part 1 - The speed switch is used to control generator startup phase and paralleling opera- '
tions. This is the source of the signal to shutoff the starting air and close the EDG cross tie breaker at 200 RPM, start the ESW pump and flash the generator fields at 400 RPM, and other EDG control functions. The switch is no longer manufactured and parts are unavailable. The proposed modification will provide a new enclosure for the speed switch below the ,
existing engine control panel and replace the device with a new model !
speed switch. Movement of the switch will facilitate calibration making it more accessible than the old switch inside the control panel, Governor Shutdown Coil Logic, MOD F1-87-079, Part 2 - The EDG governor !
controls generator speed under varying loads by moving the control arm ;
that modulates the injector The shutdown solenoid valve presently ,
de-energizes to dump c.ontrol oil which positions the governor at minimum l speed, shutdown. The proposed modification will reverse the governor shutdown solenoid valve logic to be energized to operate therefore L preventing EDG shutdown and/or allow EDG startup without DC powe This modification will benefit EDG operation by preventing unit shutdown upon !
> loss of DC control power and allow development of a procedure to startup !
the EDGs without DC control power. Both of the above will improve EDG reliabilit Crankcase Vacuum Monitoring, MOD F1-87-079, Part 3 - The magnitude of the crankcase vacuum gives a good indication of the relative condition of the L diesel engines and is a useful parameter for trending purposes. Presently '
there is no accessible indicator of crankcase vacuum. The proposed modification will add a new vacuum gage to the control panel to indicate crankcase vacuum. This will facilitate the evaluation of EDG performance and, therefore, improve EDG reliabilit .__- --_ -
_ _ _ _
.
. .
-23-
.
Lube Oil Modernization, MDD F1-87-137 - This is the proposed modification mentioned in the maintenance section of this report (manufacture's Maintenance Instruction 9644, dated July, 1980). The modification includes the addition of one new pump, rearrangement of the circulating oil piping, and changes to the main lube oil flow path to maintain a full condition in the accessory equipment (e.g. turbocharger). It is expected that this modification will eliminate the procedural precaution to not restart the EDGs during the cooldown period following extended unit operatio Since this modification improves engine lubrication and allows the limiting precaution to be removed, its implementation will increase EDG reliabilit During discussions with the plant staf f, an apparent lack of adequate engineering support to plant operation was noted. Notable examples were the timeliness of the lube oil modernization and a tool board installation in "A" EDG roo In order to ev$luate this, computerized lists of modifications that are installed, engineered but not installed, active but not engineered, and proposed but not scheduled for engineering were reviewe In the last two years (since 1/1/86), approximately 145 modifications have been installed at FitzPatrick. There are presently approximately 274 modifications in progress (not yet engineered and/or not yet installed)
and approximately 282 modifications not yet in the engineering work syste Based on this review, it was concluded that engineering support for plant operation needs may not be adequate to process the backlog. This was discussed with licensee management who indicated that increased engineering support at the plant including the assignment of system engineers is a budget proposal for fiscal 198 .6 Insgection of EDG Equipment Visual inspections of the two EDG switchgear rooms and four EDG rooms were conducted to assess the condition of the equipment, as-built location and proper identification, environmental conditions, accessibility for main-tenance, housekeeping and fire protection adequac Detailed inspection by the team identified several concerns in EDG Switchgear and individual EDG Room These concerns were discussed with licensee and were satis-factorily resolved with the exception of the followin .7 Identified Problems / Concerns Moisture accumulates in the bottom of compressed air system tanks and has
. caused rust and crud problems with the starting air systems at other facilitie Although the licensee has not had EDG failure due to rust or crud in starting air components in recent history, the failure of the A0 to blowdown all starting air tanks is a concern. Based on their corrective actions on the A0 failure and their program to inspect, repair and/or replace all starting air components o, a frequency conservatively based on operating experience, this concern should not reduce EDG reliabilit _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ ___
..
-24-
.
The common fuel oil line from the F0 pumps to the day tank that had chains from the overhead crane draped on them raises a reliability concern. The licensee committed to install brackets to hold these chains during the August 1988 outage. This modification, along with the available F0 cross-tie from the companion EDG F0 system, reduces the concern to an acceptable leve The lack of emergency lighting for the "A" EDG control panel and the north side of the "D" EDG room remains a concern. The inspector viewed these areas with normal lighting turned of The meter readings and meter and switch labeling for "A" EDG were unreadable and egress from the north side of "D" EDG room would be unsafe. The same areas in the other two EDG rooms are adequately lit, and there was no justification for the difference in design. Work orders were initiated to install emergency lightin The amount of movable equipment (fire extinguisher carts, portable stairs, 55 gallon drums, gang and equipment boxer, etc.) is an equipment safety concer In the event of a seismic event, such equipment might damage EDG components needed for plant safety. A licensee's standing order was issued to eliminate this concer .8 EDG Availability / Reliability The licensee provided a Time Series Analysis (TSA) of component failure events that is part of their development of a plant specific PRA. This report states that the total number of corrective maintenance (CM) activities for the EDG system, since the 1975 unit startup, has been 214. An average of 18 CM activities are occe* ring per year. The CM activities are divided among equipment groups as follows: pumps - 5%, valves - 8%, instrumentation and controls - 37%, relays and contacts - 4%, indicating lamps - 144, immersion heaters - 44, air compressors - 64, and miscellaneous - 22%.
Preventive maintenance is not separated from corrective maintenance since the data is based on quantity of work order The report gives some recommendations for improving availability. The inspector considered the recommendations helpful. One table, in the failure mode effects and criticality analysis (FMECA) section, that should be used for maintenance planning shows the frequency at which certain equipment fails and, therefore, the overhaul or replacement frequency. The FMECA report provides data through 1985. The analysis method for the given data appears soun The licensee also provided the team with EDG availability for the last two year In 1986, the "A" and "C" EDGs were out of service a total of 19.16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> In 1987, the "B" and "D" EDGs were out of service 9.92 hours0.00106 days <br />0.0256 hours <br />1.521164e-4 weeks <br />3.5006e-5 months <br />. All EDGs were in service the remaining periods up to the date of the inspection in 1988. According to the licensee's calculations, this makes the EDG Availability, based on hours required to be operable by TS, as follows:
Year A&C B&D
............ ...... ......
1986 0.9976 1.0000 1987 1.0000 0.9984 1988 to-date 1.0000 1.0000
.
..
~25-
.
This more recent data indicates considerable improvement in EDG avail-ability over the TSA and FMECA analyses for the earlier years of plant opc-ation dise"* *cd abov .9 Conclusion Based on this inspection, it is concluded that the on-site emergency AC power supply system is designed and maintained to provide high reliabilit The assignment of EDG 1ead engineers to follow-up on EDG specific and generic problems is viewed very positively. In spite of the minor operations, surveillance, and engineering problems discussed above, the EDG are maintained at a high availabilit .0 Emergency Core Cooling Systems (ECCS)
The High Pressure Coolant Injection (HPCI) system and the Low Pressure Coolant Injection (LPCI) mode of the Residual Heat Removal (RHR) system and the Reactor Core Isolation Cooling (RCIC) system were evaluated to assess their adequacy for performing their ECCS function The HPCI system is provided to ensure that the reactor is adequately cooled to limit fuel clad temperature in the event of a small-break loss of coolant accident (LOCA). The HPCI system permits the plant to be shut down while maintaining sufficient reactor vessel water inventory until the reactor vessel pressure is below the pressure at which the LPCI mode of the RHR system can maintain reactor vessel water leve The LPCI mode of the RHR system is designed to restore and maintain water level in the reactor vessel for core protection in the event of a large-break LOC The RCIC system was also evaluated because of its operational relationship with HPCI and its importance to plant operations subsequent to loss of of f-site power or major transients (e.g. MSIV closure) in the power conversion syste System availability for HPCI, RCIC and RHR was assessed by reviewing the adequacy of system design for operations and maintenance. Critical reviews of important components were conducted to determine the potential for failure from deficient procedures and the adequacy of corrective action as a result of past failures. Also, engineering support activities were reviewe The inspection scope is detailed below:
..
- System design and operation as defined in the FSAR and Technical l Specifications were reviewed against the various plant implemen.ing ;
procedure '
l
- System walkdowns were conducted to observe the current installed I status of major component * Interviews with engineering and maintenance personnel were conducte .
_ _ _ __ . _ _ _ _ _ . ____________ ______-______ _______ _______ ____ ________ ______ __ ____ _ _ _ _
.
.-
-26-
.
- Operating, test and maintenance procedures and associated records were reviewe * Major equipment failure data with any associated licensee event reports (LERs) were reviewed. Root cause analysis and corrective actions were evaluate *
Vendor manuals for pumps and turbine were reviewed with emphasis placed on the vendor recommended periodic operational and preventive maintenance checks as compared to the actual plant practice concern-ing these item * Administrative controls exercised by the various plant personnel who perform work on major system components were reviewe .1 General ECCS Observations The inspection had the following general observations during the ECCS revie General Electric had issued Service Inf ormation Letter (SIL) No. 323 in March, 1980 to inform BWR plants of a potential problem pertinent to ECCS pump mechanical seals. This SIL addressed the possible incompatibility of the hole size in the suppression pool ECCS pump suction screens versus the hole size in the orifice for the ECCS pumps seal flushing circuit. Some plants under construction had been found to have suppression pool ECCS pump suction screens with hole sizes larger than the orifices associated with the cyclone separator in the pump seal flushing water circuit. If this orifice is smaller than the holes in the suppression pool ECCS pump suction screen, there is a possibility that under continuous long-term operation the pump seal flushing piping might be plugged and eventually cause seal failur This SIL is applicable to FitzPatric The licensee had reviewed it in 1980 and modification FI-80-013 was assigned to resolve the proble However, this modification was never performed and was eventually cancelled. The licensee reviewed this issue again in February 1988 and issued work requests for the affected ECCS pumps to inspect the cyclone separator lines and measure the size of the internal orifice The inspector reviewed these work requests and noted that the licensee had estaolished the lowest level priority (Level 3) for this wor The
, inspector noted that this work priority appeared to be inconsistent with the safety significance of this issue especially in view of the late response to the 1980 SIL. The licensee revised the work priority on the
'
' applicable work requests to Level 1 and further noted it was their intention (even with the level 3 priority) to perform this work in the upcoming refueling outage. The inspector acknowledged the reassignment of work priority and had no further concerns in this regard. However, the inspector noted that this issue would continue to contribute to added risk from a PRt standpoint until the orifices are inspected and modified if necessar The added risk exposure is probable when one considers the potential for the presence of debris in the suppression pool under accident condition _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ . _ _ _ _ - _ _ _ _ - _ _ . - -_-_ _ _ _ _ _ _ _ _ _ _ _ _ _
.
o .
-27-
.
The inspection team encountered several examples of inadequate work control activities with the most significant item being the dismantled pipe supports (see section 4.4) for the A and B loop RHR pump minimum flow bypass lines. Other items observed were:
Hose clamps were in place to secure the RCIC turbine auxiliary lube oil sum This was not the intended arrangement recommended by the vendor and the licensee was unable to explain how the hose clamp installation was originally authorized. During the inspection the licensee prepared minor modification M1-88-163 to properly justify the existing installation and be consistent with site procedures. This is another example of the viola-tion addressing the licensee's failure to follow approved procedures (50-333/88-15-01).
The electrical junction box for 13-MOV131 (RCIC turbine steam supply isolation valve) had the appearance of being inadequately supported since the box was not directly attached to any permanent structure. Even though unistrut members were attached to the rear of the junction box, they were not connected to any structure. This junction box is currently supported by several conduits that attach to it. The licensee's engineering person-nel were unable to explain the presence of the unistrut at the rear of this junction box and concluded that the existing support condition was part of original plant constructio An engineering calculation was performed to check the stresses in the electrical conduits that support this junction box. The stresses were acceptable based on the applicable structural code allowable values. The inspector had no further questions in this regar The licensee demonstrated a positive attitude toward maximizing ECCS equipment availability. This was evidenced by the licensee's practice of removing ECCS equipment from service for a maintenance activity only after thoroughly reviewing the need for removal from servic .2 HPCI Systems Review A. Operations Review of the system design in the FSAR indicated that a strainer (desig-nated F-9) exists in the torus suction line for the HPCI pump. The inspector noted that this strainer was not periodically flow tested or
$,- , inspected. This is contrary to the licensee's commitment in Section of the FSAR. The inspector indicated that this was a deviation (50-333/
88-15-02). Subsequent to the exit meeting the inspector was advised that a Surveillance Test (ST) procedure ST-4M had been developed to do this testing and that the test was performed satisfactorily on August 19, 198 _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___________ ____ ____ ___ _
.
i
. .
-28-
-
,
In addition to conducting a walkdo.;n of the HPCI system, the inspector
observed the performance of ST Procedure No. F-ST-4B on August 18, 198 During this test the inspector noted loud banging of HPCI turbine exhaust check valve HPI-65 evidencing repetitive slamming of the check valve dis The cause for this undesirable action was attributed to the test point selected for determining HPCI turbine speed and obtaining the resultant pump head and flow. The licensee noted that the HPCI turbine exhaust check valves were scheduled for replacement in the upcoming refueling
outage. The licensee also agreed to revise F-ST-4B, if similar check valve action occurs after valve replacement.
- The inspector reviewed the operating and surveillance procedures for the HPCI system and found several discrepancies. When shutting down the system, the HPCI operating procedure directs that the flow controller be placed in manual and reduced to minimum prior to tripping the turbin The procedure then directs that the controller be returned to automatic, but does not specify that the flow rate setpoint be returned to the required setting. This could adversely affect the availability of the HPCI system if the controller were left at the minimum setting.
- Technical Specifications require tr,at suppression pool temperature be
- monitored continuously and logged every five minutes while performing any
testing that adds heat to the suppression poo The HPCI surveillance procedure does not require continuous monitoring or logging of suppression pool temperatures. The procedure has a step for cancelling a computer printout of suppression poni level and temperature but there is no step that initiates this printout. In practice, the operators routinely utilize the computer to monitor and log suppression pool temperature during HPCI surveillance testin Also the surveillance procedure contains a caution note to trip the turbine if turbine vibration exceeds 2 mils. The vibration instrument on the 09-3 panel was out of service during the performance of F-ST-4B and the operator did not appropriately note this condition in the remarks section of the test sign-of The inspector informed oper ations personnel of this discrepanc The operations personnel acknowledged the inspector's observations and agreed to take action, as required, to address these observations. The licensee was properly monitoring the turbine's perfor-mance since an auxiliary operator was present locally at the HPCI turbine / pump during the S Hence there was no immediate equipment concer b The above procedural discrepancies were discussed with the license The licensee agreed to review this matter for incorporation during the next scheduled procedure revisio ___. . _ _ _ _ _ _ ______ _________ _
.
O *
-29-
,
B. Maintenance The inspector noted several items associated with the HPCI turbine lube oil syste On April 24, 1987, pressure switch PS-1 came loose from its normal mounted position causing a big shift in its setpoint and continuous operation of the auxiliary lube oil pump. Work request 54227 was issued to repair and recalibrate PS-1 and the work was completed the next da The inspector discussed these repairs with licensee personnel to determine if the cause of the problem (e.g., equipment vibration) was known and if the current mounting of the PS-1 was considered to be a Seismic Category I installation. Howevt. , the design bases for the switch were not available for review at the time of the inspection. This item is unresolved (50-333/88-15-03), pending completion of the licensee actions to document the required informatio On February 19, 1988, the oil filter in service caused a filter high differential pressure alarm during the performance of test FT-ST-4 Operations personnel cleared the alarm by shifting filters and placing the installed spare into service. Work request 56750 was initiated to clean or replace the dirty filter element. Further discussions with the licensee indicated that a spare filter element was not available on site until June, 198 The licensee intends to perform this work during the upcoming refueling outage. The inspector noted that this delay in installing a clean spare lube oil filter element reduces availability from a PRA standpoint, as the licensee is required to declare HPCI system inoperable if the second filter element is also out of servic In reviewing the history of corrective maintenance actions it was apparent that the licensee placed a high level of emphasis on maximizing HPCI availabilit In general, corrective maintenance on key HPCI pump / turbine components and MOVs was performed quickly. It should be noted that 23MOV-14, 15 and 16 (turbine supply isolation valves) are scheduled for replacement during the upcoming refueling outag The inspector reviewed the I&C effort pertinent to the HPCI system and several sets of data concerning instrument maintenance procedure (F-1MP-23.5)
for the calibration of HPCI oil pressure instruments. One set of data included the satisfactory retest of PS-1 for WR 54227. Also, discussions with I&C technicians indicated that they were familiar with administrative controls concerning the operation of instrument valves and the proper use of electrical jumpers such as those used for local HPCI turbine speed
.
control during the overspeed trip tes .
. .
-30-t 4.3 RCIC System Review A. Operations Review In reviewing the design of the RCIC system the inspector noted that the suppression pool suction line to the RCIC pump has a strainer plate (designated F-8) similar to the HPCI pump. This suction line is not periodically flow tested. However, it appears that although credit for the RCIC system may not be taken in the FSAR, the Technical Specifications do contain operability requirements for the RCIC system. This matter also calls into question the extent of testing that should be performed per ASME Section XI for those RCIC system valves in the suppression pool suction line. The licensee will meet with the NRC staff later this year to discuss this matter plus other issues pertinent to the next 10 year interval IST program for pumps and valve The inspector was advised by the licensee that the RCIC turbine exhaust check valves did not evidence the same disc slamming action during the periodic RCIC pump ST as did the HPCI turbine exhaust check valve However, both RCIC turbine exhaust check valves (04 and 05) were scheduled for replacement during the upcoming refueling outag The inspector reviewed the operating and surveillance procedures for the RCIC system and found several discrepancies. Similar to the oiscussions under HPCI System (section 4.2), the operation procedure for the RCIC system also does not address suppression pool temperature and level limita-tion while operating the RCIC system which adds heat to the suppression pool. In addition, the RCIC surveillance procedure does not indicate that monitoring and logging of suppression pool temperature while testing RCIC is a Technical Specification requiremen This could result in the monitor-ing and logging of suppression pool temperature being inadvertently omitted if there were a problem with the plant compute B. Maintenance Review With the RCIC pump / turbine being smaller and less complicated than the HPCI equipment, the maintenance effort is likewise less complicated. This fact is evidenced by the lesser amount of RCIC out of service periods to perform corrective maintenance. Based on the condition of the RCIC system equipment observed during the system walkdown and discussions with main-tenance and I&C personnel, the inspector determined that the maintenance,
,< _ . calibration and testing of RCIC equipment, controls and instrumentation were being performed adequately. No adverse findings developed which had the potential for adding risk from a PRA standpoin _ _ _ - - .- _ -. - _ .
.
o *
-31- !
.
An instrumentation discrepancy was identified between the RCIC (PI-96) and HPCI (PI-116) pump suction pressure indication in the control room. The ;
inspector noted that the RCIC pump suction pressure indicated 40 psig and HPCI pump suction pressure indicated 20 psig. Troubleshooting showed that :
the instrumentation was functioning properly. The cause of the higher !
i RCIC suction pressure was attributed to trapped pressure in a section of piping, bounded by several tight seating check valves, which is pressurized i
, by the RCIC condensate pump (P-4). This explained the discrepancy and the f
- inspector had no further question in this regard, i i
4.4 RHR (LPCI Mode) System Operations and Maintenance Review l
'
The major components in the RHR system, namely the RHR pumps and valves, i have been relatively trouble-free since September, 1983. Based on l 3 d hcussions with engineering personnel and review of engineering
!
information, the inspector determined that a major modification was made i to the RHR pump discharge piping. This modification is primarily l
- responsible for the recent good performance of the RHR system. The ,
, 16-inch check valves (RHR-42A,B,C,0) located at the discharge of the RHR pumps, failed previousl r
.
The licensee has devoted considerable effort to address check valve i l problems, in general, at JFNPP. Several initiatives have been und?tway as ;
) part of a check valve improvement program. Also, the mechanical engineering supervisor had recently presented a paper to the ASME on the check valve
'
(RHR-42A, B, C &D) failures describing how they were corrected at :
FitzPatrick. A number of check valves are currently scheduled for replace- !
i ment in the upcoming refueling outage. However, it would be premature to ,
, draw any overall conclusions from this check valve improvement program in i
light of earlier comments made in Section 4.2.1 concerning the past operation of the HPCI turbine exhaust check valves and comments below
'
concerning RHR/RHRSW check valves RHR-177A and The inspector reviewed the RHR pump design specifically for the impeller wear ring failure identified in NRC I&E Information Notice 86-39. The licensee reviewed this issue and concluded that the JFNPP RHR pumps were not susceptible to the wear ring failures since the material used by the pump vendor (Byron-Jackson) was different from that used in the pumps (Bingham Willamette) in the information notic During the system walkdown the inspector noted that the RHR system can be supplied with service water from the RHR Service Water (RHRSW) system is a method of last resort for core cooling. A cross tie exists between the RHR and RHRSW systems for both loops A and The flow path to the RHR system would be through 2 MOVs (II.8A/B and 149A/B) and a check valve (177A/B). However, the check valves (10-RHR-177A/B) have not been periodically tested. Also, the inspector noted that in February, 1987 the licensee identified the disc from check valve 10-RHR-177B to have been missing since initial construction in 1975. WR-052178 and QC deficiency
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _
,
. .
-32-
.
and corrective action report identified the problem. A new valve disc was installed in 10-RHR-1778. Also, check valve 10-RHR-177A was disassembled in March 1987 and its internals were found intact. The licensee ack-nowledged the inspector's observation and agreed to review this matter for establishing periodic tests or inspections for these check valve On August 15, 1938, during a walkdown of the RHR system, a detached pipe support was observed. The pipe support was located near the B and D RHR pumps in the east crescent of the reactor building. The support was anchored at one end. The location of the support indicated that the free end had been attached to the common RHR miniflow line. An inspection was conducted on the A and C RHR pump miniflow line for a similar pipe suppor The geometry of the A and C miriflow line is slightly different and a detached support was not observe The inspectors conveyed th91r concern for the detached pipe support to the license Further investigation by the licensee determined that the detached pipe support (H-10-74C) was designed to support the common four inch RHR miniflow lin On August 16, 19S3 at 3:00 p.m. the licensee declared the LPCI mode of RHR incperable (Tech Spec 3.5(b)) due to the detached pipe suppor The pipe support was replaced and the LPCI mode of RHR was declared operable four hours late On August 17, 1938, the licensee determined that a pipe support (H10-63) on the A and C RHR miniflow line was also missing. The licensee took similar corrective actions and replaced the pipe suppor The licensee conducted an investigation to determine the circumstances surrounding the pipe support removal. The supports were removed in January 1988 by Work Request No. 54931. The intent of the work recuest was to perform a UT (P-Scan) on the RHR miniflew lines. A note in the work package stated "temporarily disconnect existing pipe supports to permit power brushing of piping. Reconnect support immediately thereafter."
The pipe supports were not reconnecte A dis:ussion was held between the inspector and the licensee concerning the circumstances surrounding the missing support, The licensee stated that Chicago Bridge and Iron (CBI) had been contracted to prepare the pipes for the UT (P-Scan) inspectio EBASCO Services performed the actual UT Inspection. A prejob walkdown with the CBI foreman and licensee was conducted prior to the start of wor The removal of the pipe supports was not discussed during the walkdown. The licensee
,m indicated that subsequently CBI personnel removed the supports based on discussions with EBASCO personnel whom CBI believed to be appropriate for authorization of such work. The poor communications during the walkdoor,,
and the lack of control of both contractors appear to be the major reasons for the support was left detache .
. .
-33-
.
Note (1) on the sketches used to perform this work stated "Temporarily disconnect existing pipe support to permit power brushing of piping-reconnect support immediately thereaf ter." This step was not properly j implemented. This is yet another example of a violatior (50-333/88-15-01)
i of Technical Specification 6.8(A) which states in part, "Written procedures and administrative policies shall be established, implemented
- and maintained that meet or exceed the requirements and recommendations 1 of Section 5 "Facility Administrative Policies and Procedures" of ANSI l 18.7-1972 and Appendix A of Regulatory Guide 1.33, November 1972."
l The licensee, with the assistance of Stone ard Webster, performed an operability evaluation of the miniflow lines with the pipe supports t
remove The stress analysis indicates that the maximum calculated stress
, is less than the allowable stress. The calculation indicated the system j would remain operable with the pipe supports remove Review of F-ST-2S for the RHR inboard injection testable check valves
- (10-A0V-68A & B) indicated that the procedure allows 3 alternatives for q satisfactory valve performance as follows
- Disc indication (panel 09-3) or Air operator indication or Air operator position (in drywell).
No comments are included to track which test method is used. Consequently, current testing without a common reference point does not readily enable trending of valve performance. The licensee testing and performance supervisor committed to revise this procedure and improve its ability to monitor and track valve performance. Such an improvement would be a positive factor from a PRA standpoin .5 Conclusions Although a violation and deviation of NRC recuirements and an unresolved item concerning ECCS components were identifitd, the inspector concluded that these instances were isolated and not inCicative of practices throughout the facility. At the end of the " spection there were no known safety issues that would prevent the ECCS equ.pt ent reviewed f rom perform-ing its intended safety function .0 Miscellaneous Systems s
5.1 Emergency Service Water The Emergency Service Water system (ESW) is essential for EDG lube oil and jacket cooling. There are no remotely operated isolation valves Detween the pumps and EDG units. In addition, ESW is de igned to supply backup coolant, through isolation valves and check valves, to control rod drive (CRD) and RHR pump and motor coolers, safety equipment area and drywell unit coolers, and the control room air conditioning equipment. There are
.
.
9 *
-34-
.
two independent loops, each capable of supplying 100% of the required cooling water through a normally closed cross tie valve. Each pump and its discharge strainer is located in a separate bay in the screen hous The redundant systems are supplied electric power from the associated !
emergency bu The ESW pumps may be manually started from the control room and are '
automatically started by the starting of an associated EDG or by low pressure in the Reactor Building Cooling (RBC) System. Following a manual start or automatic start initiated by EDG operation, the ESW pumps supply cooling water to the EDGs and through minimum flow lines to the ;
fire pump suction bay. ESW pump starts due to low pressure in the RBC ,
system initiates injection of ESW into the RBC system by opening automatic valvas. ESW pumps are shutdown manually. This is possible only if the associated EDG is shutdown and no low pressure condition exists in the RBC system. Likewise, ESW injection into the RBC system is terminated manually and can be effected only if no low pressure condition exists in 3 the RBC syste The Screenwell system including traveling water screens and trash rates supplies water to the ESW pump suctions. There is no external motor or pump cooling water needed for ESW operatio Each ESW system has dual strainers at the discharge of the pump These strainer pairs may be shifted to facilitate the cleaning of the out-of-service strainer. This operation in performed locally. This simplistic design should be relatively free from operational problems and, therefore, very reliabl However, in early 1985, two independent circuit problems left both EDG sets inoperable (LER 85-003). During the monthly surveillance of
"A" and "C" EDG, the "A" ESW pump was declared inoperable (making these EDGs inoperable) after it tripped during startup due tc the l A-phase overcurrent trip device being set too low. Two days later, 4 while still in the 7-day limiting condition for operation (LCO) on I
"A" and "C" EDG, the "B" ESW puTp could not be shutdown folicwing "B" f and "D" EDG surveillance. This was due to problems with the engine ,
start relay for "D" ED The "D" EDG control problem was traced to a high resistance ground most likely caused by a small piece of conductive material lodged between leads. The mechanical phase overcurrent trip devices have been replaced with adjustable and test repeatable solid state device The inspector observed ESW operation as a part of the EDG monthly surveil-lance test F-ST-98 EDG Full Load Test and ESW Pump Operability Test (IST). The "A" ESW pump automatically started at EDG speed of approxi-mately 400 rpm, as designed. There was no indication of leakage, the pump l discharge and differential pressures net IST requirements, and the vibra-tion readings were within the acceptable rang Monthly surveillance of the ESW pumps is adequate to confirn operability and insures that the critical EDG cooling functions, lube oil and Jacket water cooling, are availabl O !
!
o . !
'
-35-
.
I While observing "A" ESW operation, the inspector noted the erection of :
scaffolding in the vicinity of "B" ESW pump. In addition, there were i scraps of wood and a plastic bag next to the pump, pieces of insulation in i the corner of the room, steel plate loosely wired to an instrumentation :
column ESW P28, and several cases where electric junction boxes were not i properly closed (loose or missing door clamps). There was no indication i that the scaffolding was approved. The inspector discussed the scaffold- !
ing work with the supervisor who, subsequently, inspected and approved the scaffolding erection and indicated that the scraps would be picked u These issues were discussed with shift supervision in the control room, !
and standing order (PS0) #51, Erection of Scaf folds Near Safety-Related -
Equipment, was reviewed. Although the scaffolding seemed stable, review [
of PSO #51 clearly indicated that the unit above "B" ESW pump did not meet ,
the minimum horizontal clearance requirement, in that the scaffolding was tied off in only one direction and pump instrumentation was within one I foot. Step 7.6.8 requires that for cases where one foot minimum horizontal ;
clearance cannot be maintained, the scaffolding shall be rigidly tied-off to existing structural steel in each horizontal directio This action is i necessary to assure that no damage will occur under seismic loading. The inspector reinspected the "B" ESW pump room the next day. The scaffolding, t housekeeping, and junction box deficiencies had been corrected, l The inspector reviewed the licensee's actions related to NRC Information :
Notice (IN) 86-11, Inadequate Service Water Protection Against Core Melt !
Frequenc This IN informed licensees of possible failure to provide i sufficient redundancy in the essential water system. The licensee's formal review of this issue was reviewed, By operating exnertence ;
report (OER) 860046, it was concluded that IN 86-11 did not apply to ;
JFNPp because of the two independent ESW systems providing backup to the [
normal service water system. The inspector had no further questions of this analysi l The licensee's Time Series Analysis (TSA) of component failure events states that the total number of corrective maintenance (CM) activities for :
the ESW system, since the 1975 unit startup, has been 344. An average of [
29 CH activities are occurring per year. The majority of CM activities '
are in the valve equipment group - 33%, followed by instrumentation and '
controls - 26%, pump equipment group - 19% and miscellaneous - 21%. f As with the EDG data, preventive maintenance is not separated from corrective '
maintenance since the data is based on quantity of work orders. The report gives some recommendations for improving availability. The inspector
, considered the recommendations helpful. This report, like the EDG report, contains a failure mode ef fects and criticality analysis (FMECA) sectio The FMECA data is only through 1985, so not totally relevant, toda However, the analytical method remains soun !
l,
!
I t
f f
__ _ -
!
_
.
. .
-36-
.
The licensee provided the team. with ESW availability information for the last two years. In 1986, the "A" ESW system was out of service a total of 14.20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> and the "B" ESW system was out of service 24.52 hours6.018519e-4 days <br />0.0144 hours <br />8.597884e-5 weeks <br />1.9786e-5 months <br /> total with 14.10 of these hours being for preventive maintenance (PM). Both ESW systems were in service the remainder of the time up to the date of the inspection in 1988. According to the licensee's calculations, ESW availability, based on hours required to be operable by TS, was as follows:
Year A Side B Side
............ ...... ......
1986 0.9932 0.9970 1987 1.0000 1.0000 1988 to-date 1.0000 1.0000 The licensee indicated that the 1986 total availability could be broken down to a value of 0.9982 for FMs and 0.9987 for corrective maintenanc These numbers show considerable improvement over the data used in the TSA and FMECA analyses addressed abov Overall, the ESW system is considered to be quite reliable. The licensee is in the prccess of installing another diesel fire pump in the screenwell building. In discussions with an engineer, it was learned that a modifica-tion is to be made to allow quick connection via a fire hose to the RHRS The inspector enquired whether the same type of connection be made for backup to ESW. The engineer committed to discuss this with plant manage-ment. Since the primary purpose of ESW is to provide cooling water to the EDG lube oil and jacket water coolers, it would seem that backup from a system independent of AC and DC power (diesel fire water pump) may reduce the core melt probabilit .2 Instrument Air System The instrument air (IA) system was found to be among the ten systems most likely to lead to core melt by the generic PRA. For this reason, the team chose to review the design, maintenance / surveillance, and operation of IA at the JFNP All compressed air used at the facility comes from three parallel two-stage compressors utilizing individual inter-coolers, moisture separators, and after-coolers. The compressors discharge to a common header that feeds the service air headers and two high quality IA dryers. One dryer 54n_ . is normally in service and the other unit in the automatic regeneration or standby cycle, Filters are provided upstream and downstream of the dryers to remove any particulate matte The dryers discharge to a second common haader that feeds the breathing air tank and header and the main IA supply header .
t
0 *
l-37- !
.
! I
,
'
Normally, two of the compressors are in operation, loading and unloading to maintain :,ystem pressure at 120 p'sig. During the inspection, one !'
.
compressor was running loaded and the second one running unloade The
third compressor was out of service due to high air discharge temperature for the last three days of the inspection. Work was only performed during ,
i day shifts. No backup unit was available, so failure of either operating i a
compressor would lead to partial loss of IA. The licensee identified that ;
i the problem was with the calibration of the instrumentation and not with !
- the compressor. The instrumentation was recalibrated and this compressor i was returned to service. A fourth compressor, located by the other three a
'
but not installed, has been available for the last 10 years. Its only use i has been for spare parts. Engineering indicated that a diesel air compressor i
- is being considered, but no definite plan exist *
Nitrogen is used for instrumentation and control in the drywell so that j any leakage will not dilute the nitrogen inerted primary containmen i
.
This nitrogen is supplied by an outside storage unit. IA is available in i
!
' the containment as a backup to the nitrogen and for usage during outages, f The inboard main steam isolation valves (MSIVs) and the safety relief I s valves (SRVs) are operated by nitrogen and backed up by an accumulato [
Thus, their safety function would not be affected by a loss of I !
l The outboard MSIVs are operat9d on I This would be acceptable because 1 the valves are designed to close (their safe condition) on loss of I l The ADS check valves, that prevent loss of accumulator pressure upon a !
break in the nitrogen header, are tested each refueling outage under '
F-ST-39M, Leak Rate Test of ADS Air Supply Check Valves. No test to con- t firm MSIV closure on loss of IA has been performed since original plant !
startup; however, other valve closure tests are periodically performe ~
!
NRC Information Notice (IN) 87-28, Air Systems Problems at U. S. Light l Water Reactors, references AE00/C701 (same title as IN) which describes l five different plant events. The inspector reviewed an Operating l Expe-tence Review Report, number 870111, documenting licensee actions I related to this IN. This report concludes that no further action is i required since JFNPP NPP does not have inflatable reactor cavity or refuel [
cavity seals and water intrusion has occurred once, but was corrected by !
Modification F1-86-67 which added a check valve in the service air line to i radwaste. Also, the air compressors are non-lubricated type so no oil is !
introduced. A note on the front page indicating that a review of their '
air system against the AE00 document to assess JFNPP vulnerability was in
, orde I Plant maintenance was aware of NRC IN 83-51, Failure of Main Steam Iso-lation Valves, issued July 21, 1983. The licensee is in the process of reviewing thi. issue for JFNPP. The inspector noted that maintenance procedure 50ER-SS-01-5 disagrees with F-0P-39 in that the maintenance procedure requires both pre-filter and af ter-filter for the dryer units be ;
replaced quarterly while the operations procedure says to replace these filters when the delta pressure exceeds 5 psid. From a reliability I
_ _ _ _ - _
.
.
-38-
.
viewpoint, the periodic replacement, based on historical data, may be the most desirabl The inspector walked through the Loss of Instrument Air abnormal operating procedure (F-A0P-12) with a Shift Supervisor. The only system backuo action for decreasing IA header pressure is the automatic isolatico of service air at 95 psig and of breathing air at 85 psi Based on the above, the inspector concluded that the instrument air system has high availability in spite of the apparent lack of licensee's measures to ensure reliable backups, 5.3 Automatic Depressurization System The safety function of the Automatic Depressurization System (ADS) is to lower main coolant system pressure to allow injection from the low pressure ECCS pumps in the event that system pressure is maintained but the HPCI system is incapable of maintaining water level. ADS also provides overpressure protection and is a backup to the HPCI system for pressure control when the main condenser is not available. Eleven safety relief valves (SRVs) are located in the Main Steam lines upstream of the MSIVs. All eleven SRVs exhaust steam below the water level in the suppression pool to provide condensation of steam being released. All of the relief valves are self-actuated on overpressure and can be opened manually with remote switches. Seven of the SRVs are automically opened by relay logic circuits on low water level following a time delay p ovided that a low pressure ECCS pump is runnin During automatic and manual operation, solenoid valves open to supply pressurized nitrogen to open the relief valves. Each valve has a nitrogen accumulator that has the capability to cpen the valve five times if the nitrogen supply is lost The solenoid valves and relay logic circuits are energized from redandnat 125V DC power supplie A. Surveillance Testing The inspector reviewed surveillance tests and surveillance test data for the ADS, Technical Specifications require that the following testing be performed:
once/ ope *ating cycle: A05 simulated automatic actuation test, including initiation inhibition by the override r,r switches, m4nually epen each SRV and functionally test the Valve Monitoring Sys'.em (VMS), bench check (or replace with a bench checked valve)
one half of the SRVs (all va tves must be checked every 2 operat,ng cycles) and visassemble and inspect at least one SRV once/6 months: ADS Logic Subsystem functional test (also perfor ed if one ADS valve is inoperable)
_ _ _ . . _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ -
.
L
. . l-39-
.
t
!
,
'
once/3 months: Nitrogen System pressure sensor functional ;
check once/ month: SRV Monitor (VMS) instrument check
,
,
Review of the procedures indicated that the required testing and !
preventive maintenance (calibration) is being perfnrmed adequately. The !
inspector noted that the procedure for the VMS instrument check does not (
, provide for identification of bias drifting problems on the acoustic ;
,
monitor pre-amplifiers. The inspector discussed the potential for pre-
[
l smplifier bias drift with the licensee represe9tative who acknowledged l this observation and agreed to review the procedure, t
Review of the most recent test results for the logic systems and instru- !
i mentation indicated satisfactory results during initial test performance [
! except for an unsatisfactory automatic actuation test due to an open coil !
in a rela The relay was promptly repaired and the test was reperformed ;
satisfactorily on the following da ;
,
r l During testing in Sepu.aber 1983, one SRV failed to open when manually !
l operated from the remote SRV panel due to a ground fault in the DC control l i circui The valve was operational from the control room, from ADS logic !
circuits and with respect to reactor pressure demand. After correction of i i the ground fault, the valve operated normally from the remote panel. No ,
similar problems have been note The most recent manual operation test !
, results were satisfactory with the exception of several computer points ~
'
shat did not alarm. These alarms are not required for system operabilit The SRVs have responded to all challenges caused by both system pressure I and operator demand (manual) with no failures from 1982 to presen l
B. SRV Setpoint Orift l
,
Setpoint drift in 2-stage Target Rock Corp. (TRC) Safety Relief Valves I
'
has been a recurring problem throughout the industry. Since 1982 the !
1 licensee has had 17 SRVs that had setroint values outside the allowable l j tolerance specified by Technical Specifications (+ 1 *4 of setpoint). I
All failed valves wtre refurbished and recertifte3 prior to return to the l I plant for reinstallatio The licensee has increased the frequency to l
,
tost all valves each cycle untti the setpoint drift problem is resolve ,
I
'he planned corrective action is to modify the valves by replacing the !
6 ._ pilot valve discs with new discs using a dif ferent material. The modified j valves will be installed during the upcoming refueling outage (Fall 1988). :
The licensee is participating in the BWR Owners' Group (BWROG) SRV setpoint !
i drif t test program which will monitor and compare performance of the ;
i ndified and unmodified SRV !
i !
'
nual and automatic (ADS) functions of the SRVs are not affected by the [
setpoint drift problem, previous evaluations of the effects of setpoint i
- drift have demonstrated a large margin of overpressure protection with one j SRV inoperable and other SRVs with setpoints above the nominal values 1 i
! r
.
i l
I i
e i-40- !
t
i
l
- t allowed by Technical Specifications. An evaluation is currently in l I progress that is expected to define the most limiting cases of inoperable i valves and the limiting setpoint drift corditiols which are acceptable !
with respect to overpressure protectio l
,
i l C. Conclusions, Review of the system design, surveillance testing and test results ;
indicate that the Automatic Depressurization System is designed and ;
l maintained to provide high Peliability. Because the SRV setpoint drift ;
l problem does not affect minual or automatic (ADS) operation and preliminary !
!
evaluations indicate that a large margin for overpressure protection still :
exists after taking the setpoint drift problere,into account, the relia-bility of the system does not appear to be tdversely affected. Adequate
,
!
procedural guicance and knowledgeable operations personnel are available I to provide additional assurf ace of system reliabilit !
l 5.4 The Main Steam Isolation Valves (M W l t l The M51Vs are 24 inch globe valves manufactured by Rockwell (model l l 1612JMMNY). The two series isolation va!ves in each Main Steam Line i I close a:.tomatically upon receipt of isolathn signals to.
'
(1) Prevent damage to the fuel barrior by tirn; ting the loss of reactor coolant in case of a major leak from the steam piping outside the ,
primary containmen l t
(2) Limit release of radioactive materials by c)osing the Reteter Coolant I pressure Boundary in case of gross release of radicactive m;, rials from the reactor fuel to the reactor coolant and steam, ft (3) Limit release of radioactiva materials by closing the primary [
containment barrier in case of e %.Nr leak from the Reactor Coolant !
System 'nside the primary containmen The inspecter reviewed MSIV Surveillance procedures (see Attachment 2) for f technical content and to assure compliance with Technical Specification t Requirements. No unacceptable condittuns were ider,tifie l The inspector witnessed surveillance test F-STM11. "Main Steam Isolation Valves Limit Switch Instrument Functional Test." The inspector noticed
.. .e . . that the operators conducting this test set up continuous communications [
between tus*, locations 4nd each followed u d checked off the test !
'
procedure The operators were found to have a good knowledge of the test procedure and system operation. No unacceptable conditions were identi-fied during the performance of the surveillance tes The inspector reviewed the fast closure time sost data recorded since 198 The test data indicates that M5IV E6C failed the 3-5 second clo;are time limit in 1934, 1986 and 193 The failure in 1937 required a chang: in tne Technisal Specification The Technical Specification change allowed t _ _
.
.
..
-41-
.
one valve closure time of 2-5 seconds during cycle 8. Two other MSIVs were found to have failed the closure time test on one occasion eac Closur. time adjustments to the MSIVs have accounted for approximately 25%
of the Work Requests written on the MSIVs during the past two year The inspector reviewed the Local Leak Rate Test (LLRT) data from 1977 to the present. All four main stream lines failed LLRT in 197 The data indicates that two of the four main steam lines failed the LLRT in 1980, 1983 and 1987 One of the four steam lines failed the LLRT in 1982 and 1985. The Assistant Maintenance Superintendent stated that a valve seat repair tool, purchased from Rockwell had been in use since 1979. This tool helped to reduce LLRT failures of MSIV The inspector reviewed the Work Requests written during the past two years to repair MSIV's. Recurring problems identified were Limit Switch failures, fast and slow closure times outside normal limits, air leaks, and valve seat and packing leak Nearly one half of the Work Requests were for closure times and limit switche The inspector reviewed MSIV equipment history for significant failures (i.e., stem failure, valves failing to close, disc separation). One signi-ficant MSIV event did occur in 1982. In 1982 a Reactor Scram occurred which was a result of an MSIV failure (LER 82-057). The event was caused by the main disc separating from the valve stem and closing the valv The main disk separated from the piston assembly due to an improper installation of an anti-rotation pin two months earlier. A similar event had occurred previously involving the same anti-rotation pin and valv The corrective action taken was to change the pin design and installation procedure. Similar failures have not occurred since the implementation of this corrective actio The inspector concluded that the MSIVs had been operated without a major failurt since 1982. The licensee has addressed the root cause of the disc separation with a design change to the anti-rotation pin installation procedure which has prevented further disc separation problem .0 Integrated Plant Operations The selected events (see section 1.2) were used to evaluate the licensee's procedures, training of operations perscnnel, and equipment availability in respect to mitigating the consequences of the selected
.ga- events and preventing core mel An inspection of the emergency operating procedures (EOPs) was performed by the NRC the weeks of May 23 and May 30, 1988. The inspection assessed the technical adequacy of the E0Ps and that the pvocedures could be carried out by plant staff. The details of the inspection are documented in NRC Inspection Report 50-333/88200.
I
c--
, .
-42-
.
6.1 Station Blackout 10 CFR 50 was recently amended to add part 50.63 which requires that all nuclear power plants be able to withstand and recover from a station blackout (complete loss of AC power) for a specified duration. The plant must be capable of maintaining core cooling and containment integrity for the duration of the station blackou The inspector discussed the progress of determination of the station blackout duration and development of procedures and required modifications to cope with the station blackout with the licensee representatives responsible for the evaluations. A preliminary evaluation indicated that the blackout duration to be used in determining compliance with 10 CFR 50.63 at this facility will be four hours. Presently an analysis is being performed to determine station battery capacity during a station blackou The licensee does not have a procedure that addresses a loss of all AC power, but is in the process of developing a station blackout procedure to meet the requirements of 10 CFR 50.63. The licensee is also considering several modifications that will be required to cope with a station blackou .2 Accident Sequences Various combinations of the events discussed in Section 1.2 were used to develoo accident scenarios that could lead to core melt. These scenarios wer 2d to assess the ability of the licensee's operations personnel and prc .res to respond to and mitigate the events that could lead to a core melt. A walk-through of the scenarios was performed on a full scale control room mockup with several licensed personnel acting as reactor operators and a shift supervisor. An additional scenario based on unavail-ability of heat sinks and cooling methods was walked through in the control room. This scenario enabled the inspectors to observe operations personnel, procedures and indications in the actual control roo The shift supervisor used existing procedures to direct operator actions and the operators simulated performance of these actions. Emphasis was placed on methods and indications available to identify and diagnose the events and to monitor critical plant parameters. During the scenarios, actions for mitigation of the events and preventing core melt that did not have procedural guidance (i.e. , bypassing Interlocks to allow running a diesel without cooling water) were discusse Results of the walk-throughs and discussions indicated that existing procedures are adequate to mitigate the consequences of a station blackout and the additional failures addressed by the selected accident sequenc The planned station blackout procedure is expected to further define and prioritize actions to be performed in the case of a complete loss of AC power. These actions are presently contained in various normal and abnormal operating procedures that address plant electrical system o
..
-43-
.
Results of the walk-throughs and discussions also indicated that operator knowledga is adequate to effectively mitigate the consequences of the postulateu events. LJring th9 scenarios, Control board and Drocedural fisi:1arity was evident. The operators, especially the Shift Supervisor, deconstrated t he ability to pr;oritize actions and make decisions to ensure the safety of the plan The operations personnel demonstrated a depth of knowledge sufficient to conceive of methods and perform actions to protect the core, with or without procedural guidanc .3 Equipment Availability The av;ilability of equipment to monitor plant and equipment performance, communications equipment and personnel are important factors in the mitigation of the events that could lead to core mel These aspects were evaluated during the walk-throughs of the accident sequences and during discussions with operations personne Reactor vessel level and temperature, drywell pressure and temperature, and suppression pool temperature and level must be uonitored to assess plant conditions. During a complete loss of AC power, the DC batteries supply power to instruments in the control room to monitor critical plant parameters and system operatio The Uninterruptible Power Supply (UPS)
is available unless ' A' Station Battery is los The plant computer is supplied from a separate backup battery and would also be available to monitor plant performance in case of a station blackou Communication in plant and out-of plant is possible through multiple systems and redundancies which ensure the performance of vital functions in transmitting and receiving informatio The communications systems are either self powered (battery) or they receive power from the UPS. The Gai-Tronics page/ party system and the Sound Powered Phone system are available for in-plant communications. The Plant Telephone system is available for both in plant and out-of plant communications with special features that allow for rapid notification and communication flexibilit Dedicated telephone links provide transmission lines to various Emergency Centers. The radio system serves as a redundant backup to the telephone system. It utilizes several frequencies and portable and mobile units are availabl It was demonstrated during the scenario walk-through that the minimum shift complement could adequately perform the immediate actions required y during a station blackou The Emergency Plan contains procedures for calling in additional personnel and administrative procedures ensure that on-call personnel are readily available to respond in emergencie o e-44-
.
6.4 Conclusions The results of the inspection indicated that existing procedures and operations personnel training are adequate to mitigate the consequences of events that could lead to core melt. Critical plant parameter monitoring and system operation could be performed using available indications in the event of a loss of all AC powe Communications equipment and personnel availability would be adequate to deal with the emergency. Deveiopment of procedures and modifications to meet the requirements of 10 CFR 50.63 are expected to aid the licensee further in mitigation of a station blackou .0 Licensee Personnel, First Line Supervision, Senior Management and Quality Assurance Roles in Assuring Quality and Safety As discussed in previous sections of this report the cognizant licensee personnel in all areas of inspection were knowledgeable of the system, procedure and technical specification requirements and their responsibil-ities in maintaining and operating the systems assigned to them. This was particularly evider.t during the electrical system walkdowns with electricians and ECCS and operating procedure walkdown with operationt personnel. One isolated instance of lack of familiarity with the equipment was noted during the walk through of alarm response procedures for 345 kV and 115 kV systems. The inspector concluded that this lack of familiarity is primarily attributable to training and not the ability of the personnel. Even in this instance, the operator was able to obtain the required information by contacting knowledgeable electricians in this regar First line and middle management demonstrated excellent awareness of and involvement in activities required to maintain component availability without compromising safety. For example, when the inspectors identified concerns regarding unattached and missing supports on Residual Heat Removal System's miniflow lines, the licensee declared the system inoperable and took required actions by Technical Specificatio Similarly, the licensee took action to address the immediate hardware concern without waiting for the outcome of engineering analysis to justify the observed condition. Work Request to replace the temperature control switch for the Battery Room HVAC System was another exampl Both corporate and site senior management were dedicated to assure a high level of safety at the plant. Particularly, the senior management took unw., initiatives to communicate the corporate goals and expectations to the staf The licensee also has means to recognize good performer Employee of the Month and Employee of the Quarter are examples of such employee recognition. The senior management is well aware of the weaknesses in plant and support organizations. Actions to improve weak areas are 4 50 taken, as permitted by the budget and other organization constraints. As a result, independent industry and regulatory assessments found some of the licensee's corrective actions to be slow. The licensee is aware of this criticism and is taking deliberate actions to address this issu , .__ - _ , - .-
.
.. s 45-
.
At the corporate level efforts are already underway to develop a site specific Level I PRA for FitzPatrick Nuclear Power Plant. An organization which reports directly to the Vice President, Nuc! car Services, has been in place since January of 1988 for this purpose. This organization has a manager and three full time dedicated, licensee personnel. These licensee employees were observed to be knowledgeable and adequately experienced in PRA activities. Contractor personnel are retained to perform detailed assessment required for the plant specific PRA. Management initiative to make the plant specific PRA readily useable for design changc:, maintenance and day-to-day operational activities was noteworthy. The management is committed to complete Level I PRA by January of 199 At the time of this inspection, the licensee completed the methodology document for PR Preliminary Systems Analyses were completed for eighteen out of a total of 46 systems. A parallel effort is also in place to establish a design basis document for the facility. The HPCI system was selected as the pilot system to develop the design basis document. At the time of this inspection, the licensee has received the inputs from the Nuclear Steam Supply System vendo These inputs were being reviewed by the Architect engineer. The effort for HPCI is scheduled to be complete before the end of 1988. The PRA group intends to use the design document for the 9 Q system, when complete, to validate the PRA Methodology and Process. Considering the fact that the organization responsible for PRA is relatively new, and that this organization has a very tight schedule, management attention and overview will be required to guide this organization and to assure that the PRA is completed as planne The licensee management is involved in assuring a high level of knowledge among plant personnel. For example, the licensee has spent considerable efforts to accredit its training programs in all areas of INPO accreditation. The effect of this training was evident among personnel involved in all areas of this inspectio Additionally, the site management took initiatives to discuss safety concerns or violations in inserts to the plant newspape The planned maintenance program, discussed by the licensee during the January 1988, management meeting appeared to be progressing well at the time of this inspection. The Master Equipment List (MEL) has been completed. The new MEL has about 2,450 components. The review process for MEL downgraded 1098 components and upgraded 349 components. It should be noted that the thermal switch discussed in Section 2.3 of this report
, is one of the components upgraded during the proces Another aspect of the planned maintenance program was to develop unavailability data for key safety system History of corrective maintenance on each of the safety systems inspected has been compile Efforts were underway to develop preventive maintenance frequencies based on the corrective maintenance history. The corrective maintenance history was an excellent source for the licensee to obtain the data required for unavailability, The team perceived the licensee's efforts to establish
.
. ,
-46-
.
corrective maintenance history as a positive attribute in understanding and establishing the risk and unavailability of safety systems. However, the progress towards completing the Planned Maintenance Program was assessed to be slow by previous industry and regulatory assessment In summary, the line organization, first line supervision and senior management were observed to be involved in maintaining a high level of both availability and safety. As discussed above, the licensee has additional initiatives to further enhance safety and availability of systems. While some of these initiatives were judged to be slow by previous assessments, these initiatives were judged by this inspection team to be effective and beneficial for PRA activities. This inspection concludes that the licensee management involvement in assuring quality and safety is a definite licensee strengt .1 Quality Assurance Involvement in Activities to Assure Safety and Availability In addition to routine inspections, surveillance and audits of activities to assure quality, the licensee's Quality Assurance (QA) organization is actively involved in other activities to assure reliability and availability of plant system For example, the site QA department was responsible for the development of the newly developed Master Equipment List (MEL). The MEL efforts computerized the quality classification of all plant components and made this classification readily available for use by all licensee personne At the request of the Resident Manager, the QA Department Superintendent organized the scram reduction task force in 198 The task force provided several reco.nmendations to reduce scrams and to improve reliability. At the time of this inspection all but one recommendation were implemente Other QA department activities include a matrix to assure that Technical Specification required surveillances are performed as required, and that review of all corrective action responses is done to assure that the root cause has been identified and corrected and real time in plant monitoring is don Based on this review, it is concluded that the licensee is utilizing QA as an effective management tool in assuring safety, reliability and availability at FitzPatrick Nuclear Power Plant.
m .,. . . 8.0 Unresolved item Unresolved items are matters about which more information is needed to determine whether they are acceptable, are items of non compliance or are deviations. An unresolved item is discussed in Section 4.2 of this repor .
, ,
-47-
.
9.0 Management Meetings Licensee management was informed of the purpose and scope of the inspection at the entrance meeting held on August 8, 1988. The findings of the inspection were periodically discussed and were summarized at the mini-exit meeting on August 12, 1988 and the exit meeting on August 19, 198 (Attendees at the exit meetings are listed in Attachment 1 of this report.)
At no time during the inspection was written material provided to the licensee by the inspectors. The licensee did not indicate that the inspection involved any proprietary information,
&
_
'
,,
e, ATTACHMENT 1 h
'
Persons Contacted i New York Power Authority
+ R. Baker, Maintenance Superintendent
+ P. Brozenich, Shift Supervisor F. Catella, Manager of Nuclear Training l
+ R. Converse, Resident Manager .
+*V. Childs, Senior Licensing Engineer
+* Fernandez, Superintendant of Power
+ J. Flaherty, Assistant I&C Superintendent
+ T. Herrmann, Senior Plant Engineer
+*H Keith, I&C Superintendent
+*D Kieder, I&C Supervisor i
+*0. Lindsey, Operation Superintendent
+ B. Leseno, Planning Superintendent
- R. Locy, Assistant Operation Superintendent
+ T. Moskalyk, Senior Enginear
+*R. Patch, QA Superintendent
+*D. Ruddy, Senior Plant Engineer G. Vargo, Radiation Engineering General Supervisor
+ D. Wallace, Engineering Supervisor
+*V. Walz, Technical Service Superintendent
+*R. Wiese, Assistant Maintenance Superintendent
- I!.S. Nuclear Regulatory Commission
+ J. Chung, PRA Coordinator, NRR
+ T. Green, Nuclear Systems Engineer, NRR
+ W. Johnston, Director (Acting) Division of Reactor Safety
- A. Luptak, Senior Resident Inspector
+ R. Plasse, Resident Inspector :
- Individuals, present at the mini exit meeting on August 12, 1988
+0enotes, present at the exit meeting on August 19, 1988
The inspectors also contacted other personnel including licensed operators, non-licensed operators, I&C technicians and inaintenance personnel during l the course of the inspectio :
neon-. i h
r
>
I
!
i
..~.-_------,_,-_-,_,,..-__...,.n-,__.,_--___ -
. . - . _ . _ . . _ , - , , _ - , , . , _ - , , , , - - _ - .- . , - , - , . - - _ . _ , , . . - -
.
.4 ATTACHMENT 2
-
DOCUMENTS REVIEWED 1. Electrical Systems A. Maintenance Procedures MP-57 General Electrical Maintenance MP-5 Battery Charger Maintenance MP-5 Battery Charger Maintenance MP-5 Battery Maintenance MP-5 .16 KV swg. Bus and Metal clodding MP-55 series 600 Volt Load Center Maintenance MP-5 Volt Air Circuit Breaker Maintenance MP-5 Volt load Center Maintenance MP-71 series Electrical System Maintenance MP-7 Isolated Phase Bus Link Removal for Generator Isolation MP-7 Isolation of Battery Grounds MP-71.10 LPCI Battery Weekly Surveillance Test MP-71.11 LPCI Battery Quarterly Surveillance Test (ST)
MP-71.12 125V Battery Weekly ST MP-71.13 125V Battery Quarterly ST MP-71.14 24V Battery Weekly ST MP-71.16 (MST 71-16) LPCI Battery GTR ST MP-71.20 125 Volt Battery Service Test and Charger Performance Test MP-71.21 125 Volt Battery Performance and Charger Surveillance MP-71.22 LPCI Independent Power Supply Performance Discharge Test MP-71.48 Maintenance Procedures for Reserves Station Service Transformer MP-94 Main Generator Maintenance B. Maintenance Surveillance Test Procedures No, MST-71.11, Revision 3 LPCI Battery Quarterly Surveillance Test, dated February 10, 1988 No. MST-71.21, Revision 0 125VDC Station Battery Performance and Charger Surveillance Test, dated May 6, 1988 No. MST -71.16, Revision 2 24V Instrument Battery Quarterly Surveillance Test, dated February 10, 1988 C. Operations Surveillance Test No. ST-98, Revision 24 EDG Full Load Test and ESW Pump Operability Test (Draf t)
__
@
. e 2 Attachment 2
.
D. Abnormal Operating Procedure No. F-A0P-23, Revision 5, DC Power System B Ground Isolation, dated December 22, 1987 No. F-A0P-45, Revision 2, Loss of DC Power System A, dated December 22, 1987 No. F-AOP-16, Revision 1, Loss of 10300 Bus, dated December 22, 1987 No. F-A0P-22, Revision 22, DC Power System A Ground Isolation, dated December 22, 1987 No F-A0P-46, Revision 4, Loss of DC Power System B, dated December 22, 1987 No. F-A0P-17, Revision 2, Loss of 10400 Bus, dated December 22, 1987 No. F-A0P-18, Revision 2, Loss of 10500 Bus, dated December 22, 1987 No. F-AOP-19, Revision 19, loss of 10600 Bus, dated December 22, 1987 No. F-A0P-21, Revision 21, Loss of UPS, dated December 22, 1987 No. F-A0P-7, Revision 2, Loss of 345 KV Breaker Air dated December 22, 1987 E. Operating Procedure No. F-0P-44, Revision 4 115KV System, September 23, 1987 No. F-0P-45, Revision 4, 345KV System, dated January 14, 1987 No. F-0P-46A, Revision 10, 4160V and 600V Normal AC Power Distribution, dated January 20, 1988 No. F-OP-11A, Revision 5, Mair, Generator, Transformer and Isolated Bus Phase, dated July 28, 1988 No. F-0P-118, Revision 7, Generator Stator and Exciter Rectifier Cooling Water System, dated December 22, 1987 No. F-0P-11C, Revision 13, Main Generator Hydrogen Cooling and Seal Oil System, dated May 25, 1988 No. F-0P-59A, Revision 1, Battery Room Ventilation System No. 72, dated July 12, 1979 No. F-0P-51A, Revision 16, Reactor Building Ventilation and Cooling System (RVN), dated August 26, 1987 No F-0P-43B, Revision 2, 24VDC Power Systems,
,,: dated July 10, 1985 No. F-0P-43A, Revision 7, 125VOC Power System, dated July 31, 1985 No. F-0P-468, Revision 2, 120VAC Power System, dated December 10, 1986 No. F-0P-43C, Revision 4, LPCI Independent Power Supply System, dated September 3, 1986
, .. -_ . .
- .
. [
e c 1 3 Attachment 2 e ,
, 2. Emergency Diesel Generators and Miscellaneous Systems A. Drawings OPS OP-21-1&2 Flow path - Emergency Service Water, System 46 OPS OP-39-1 Flow Path - Breathing, Instrument, & Service Air System 39, Rev 6 OPS OP-39-2 Flow Path - Breathing, Instrument, & Service Air System 39, Rev 7 OPS OP-39-3 Flow Path - Drywell, Torus, Crescent Areas IA System, Rev 6 i OPS OP-39-4- Instrument Air Reactor Building, Rev 2 OPS OP-39-5 Flow Path - Instrument Air Reactor Building, Rev 2 Procedures OPS PS0 #51 Erection Of Scaffolds Near Safety-Related Equipment, 'Rev 2 OPS F-A0P-12- Loss Of Instrument Air, Rev 6, 12/20/87 OPS F-A0P-43 Plant Shutdown From Outside The Control Room, Rev 8, 5/4/88 ,
OPS 0050-17 Auxiliary Operator Plant Tour And Operating Logs, Rev 3, 6/2/88 OPS OD50-21 Posting Of Operator Aids, Rev 1, 2/2/83 OPS F-0P-21 Emergency Service Water (ESW), Rev 10, 12/22/87 OPS F-OP-22 Diesel Generator Emer~gency Power, Rev 15, 9/9/87 OPS F-0P-39 Breathing, Instrument, And Service Air Systems, Rev 16, 4/13/88 OPS F-ST-98 EDG Full Load Test And ESW Pump Operability Test (IST),
REV 23, 9/9/87 - Also Draft Rev 24 ;
OPS F-ST-39M Leak Rate Test Of Ads Supply Check Valves, Rev 1, S/30/85 l OPS F-ST-01B MSIV Fast Closure (IST)*
OPS F-ST-010 MSIV's, Main Steam Line Drain Valves and Reactor Water Sample Valves Logic Functional tes OPS F-ST-011 Main Steam Isolation Valves Limit Switch Instrument '
Function test.
'
l
- OPS F-ST-01K Main Steam Line Isolation
- Valves, Main Steam Drain !
Valves and Reactor Water Sample Valves Simulated Automatic Isolation Test.
, OPS F-ST-400 Daily Surveillance and Instrument Chec MNT MP-5 Fuel Oil Transfer Pump Maintenance, Rev 1, 7/3/85 v,p MNT MP-5 Maintenance Of Diesel Engine Turbocharger, Rev 1, 2/11/87
<
MNT MP-5 EDG Power Assembly Maintenance, Rev 1, 8/3/88 MNT MP-5 Procedure For EDG Lube Oil Cooler Maintenance, Rev 1,
8/3/88
MNT MP-5 Mechanical Preventive Maintenance For Diesel Engine &
Auxiliaries, Rev 2, 8/4/88
!
.
+ - - , - - - , . - . . . ~, .,.m.,..,v,-c,_.., , _ - , ,_ , . , - _ . , , , , . - , , , , _ , , _ _ _- , -
'-'"r '* -" ' " - - ' ' * * ' - ' " ' - ' " ' ' - -#--'"-TV
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
C
e c,
.
,
4 Attachment 2 e
MNT MP-52.10 Electrical Preventive Maintenance For Diesel Engine &
Auxiliaries, Rev 1, 2/17/87 I&C F-ISP-90 4KV Emergency Power Buses Undervoltage Relay Instrument Calibration, Rev 2, 8/84, And Revision Request 90-1, 4/22/87 I&C F-ISP-91 4KV Emergency Power Buses Undervoltage Timer Instrument Calibration, Rev 2, 8/84 C. Reports GM Electro-Motive Discussion of 2-Cycle Diesel Engine GM Elect"o-Motive Maintenance Instruction 9644, Jaly 1980 LER 50-333/85-003, Redundant EDG System Inoperable, 3/7/85 OER Number 860046, Review Of NRC In 86-011, Inadequate Service Water Protection Against Core Melt Frequency OER Number 870111, Review Of NRC In 87-28, Air System Problems At U. Light Water Reactors 3. Emergency Core Cooling Systems A. Operations Surveillan:e Test Procedures No. F-ST-48, Rev.34 - HPCI Flow Rate / Pump Operability / Valve Operability Tests No. F-ST-25, Rev. 11 - Valve Testing - Residual Heat Removal No. F-ST-2R, Rev. 16 - RHR Service Water Pump and MOV Operability Test No F-ST-2B, Rev. 9 - RHR Pump Operability and Keep Fuel Level Switch Functional Test No. F-ST-2A, Rev. 21 - RHR Pump Flow Rate Test No. F-ST-2C, Rev. 21 - RHR MOV Valve Operability Test No. F-ST-24A, Rev. 23 - RCIC Pump and Valve Operability / Flow Rates Test B. Instrument Maintenance Procedures No. F-IMP-23.5 - HPCI Turbine Oil Pressure Instruments Test and Calibration No. F-!MP-13.1 - RCIC System Pressure Indication Instrument Test and Calibration No. F-IMP-23.1 - HPCI System Pump Pressure Indication Instrument Test and Calibration 4 C. Work Request No. 56629 dated 2/4/88 - Disassembled and inspect both HPCI pump cyclone separators and measure size of internal orifice No. 54227 dated 4/24/87 - HPCI lube oil pressure switch PS-1 repair No. 56750 dated 2/19/88 - FIPCI lube oil filter replacemen .
.
'.
,
5 Attachment 2
D. Vendor Manuals HPCI Turbine, 23-TV-2, P.O. No. AP-1, Terry Turbine HPCI Pump Assembly, 23-P-1, P.O. No. AP-1, Byron-Jackson RHR Pump, Manual No. 8020 1E-3525, Byron-Jackson RCIC Instruction Manual - Terry Turbine, 13-TV-2, RCIC Turbine RCIC Instruction Manual-Bingham Pump, 13-P-1, RCIC Pump.
m ... .