IR 05000219/1989029
| ML20055C319 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 02/16/1990 |
| From: | Young F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20055C318 | List: |
| References | |
| 50-219-89-29, NUDOCS 9003020084 | |
| Download: ML20055C319 (66) | |
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.- < . U._S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No._ 50-219/89-29 Docket-No.
50-219 License No.
DPR-16 Priority -- Category C Licensee: GPU Nuclear Corporation 1 Upper Pond Road Parsippany, New Jersey 07054 i Facility Name: Oyster Creek Nuclear Generating Station Inspection Conducted: December 3, 1989, - January 6, Ifs 0 Participating Inspectors: M. Banerjee, Resident Inspector E. Collins, Senior Resident Inspector D. Lew, Resident Inspector ' dM u d(d% Approved By: Francis Young, Actinpiction Chief Date Reactor Projects Section 4B Inspection Summary: Inspection Report No. 50-219/89-29 for December 3, 1989 - January 6, 1990 Areas Inspected: The inspection consisted of 230 hours by resident. inspectors.
The areas inspected included observation and review of plant operational events (1.0), condenser vacuum transient (2.0), Unusual Events due to low intake water level (3'.0), simultaneous movement of two control rods (4.0), fire caused by a . failed relay (5.0), poter.tial-leakage of contaminated water from the waste surge tank (6.0),' scram air header pressure value (7.0), control rod drive uncoupling rod measurement (8.0), torus water level increase (9.0),-defective respirators (10.0), inoperable stack radioactive gas effluent monitoring system (11.0), maintennnce observation (12.0), and previously opened inspection findings (15.0).
Results: Overall, the plant was operated in a safe manner. The plant was shutdown during this period to perform a condenser low vacuum calibration surveillance.
The surveillance was performed when the operability of the condenser low vacuum scram setpoints was questioned.
The intake canal water level was abnormally low during this period.
The low intake water level resulted in the declaration of three Unusual Events on 12/4/89,.12/22/89 and 1/3/90.
Five previously opened items were closed; five previously opened items were updated. One previously opened item regarding environmental qualification was reviewed. A lack of documentation of component environmental qualification was' identified; however, the violation was not cited based on licensee's identification and corrective actions.
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, ,.. .., .- .- , i TABLE OF CONTENTS Page ' 1.0 Review of Plant Operations (71707)*............... I 1.1 Chronology-of Operations Events.............. I 1.2 Control Room Toufs....................
1.3 Facility Tours.......................
2.0 ' Condenser Vacuum Transient (93702, 71707)............
3.0 Unesusal Events Associated with Low Intake Water Levels (93702).
4.0 Inadvertent Movement of Two Control Rods (93702)........
5.0 Control-Room Panel Relay Fire (93702)..............
6.0 Potential Waste Surge Tank Leakage (93702, 71707).........
7.0 Scram Air Header Pressure Value (93702).....
....... ~' 8.0 Control. Rod Drives Uncoupling Rod Oimensions (93702)......
9.0 Torus Water Level Increase (93702)...............
-10.0 Defective Respirators (93702, 71707).............. 13.
11.0 Radioactive Gas Effluent Monitoring System (RAGEMS) Out of Service (93702).....................
12.0 Monthly Maintenance Observation (62703).............
13.0 Enforcement Conference.....................
14.0 Safeguards Meeting (30702)...................
15.0 Previously' Opened Items (92702,- 92701).............
16.0 Inspection Hours Summary.
................... .17.0 Persons Contacted / Exit Meeting (30703).............
ATTACHMENTS Attachment I: List of Personnel Contacted Attachment II: Enforcement Conference Attendees Attachment III: Enforcement Conference Presentation Attachment IV: Safeguards Meeting Attendees
- Numbers in pareathesis indicate the NRC inspection procedure used.
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I ] .. , , - s, .. . 9ETAILS 1.0 Plant Operational Review i 1.1 Chronology of Operational Events At the beginning of this inspection period, the plant was operating < at 100% power. The plant had just completed its 68th day of contin- ! uous operation with the turbine on line. No technical specification
action statements were in effect.
The following lists the major plant events which occurred during this inspection period.
< 12/4/89 An Unusual Event (UE) was declared as a result of low - -- intake water level. Details of this event are described in paragraph 3.0.
12/5/89 Af ter the intake water level recovered above the UE -- level and adequate margin above the action level was attained, the Unusual Event was terminated.
Reactor power was reduced to 81% to facilitate maintenance on the "B" North condenser.
12/6/89 After completing maintenance on the "B" North l -- condenser, power ascensfon to 100% power was commenced.
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12/7/89 As a result of an operator error, cooling water flow -- was lost to the "B" condenser.
Indicated "B" condenser vacuum dropped below the low vacuum scram setpoint on ene instrument.
> No automatic scram occurred.
Reactor power was reduced to 85% power to mitigate the condenser vacuum transient.
Reactor power was returned to 100% approximately ten hours later. During the next shift, a reactor shutdown was commenced to perform a ' condenser low vacuum calibration surveillance.
Details of this event are described in paragraph 2.0.
< . ' During performance of Station Procedure 636.4.003, "Otesel ' Generator Load Test," No. 2 Emergency Diesel Generator (EDG) load could not be raised above 2600 KW, No. 2 EDG was declared inoperable at 2:40 a.m.
After performing a seasonal adjustment on the No. 2 EDG, the surveillance was reperformed satisfactorily; and, the No. 2 EDG was declared operable at 1:20 p.m.
The sever day technical specification action statement was terminated.
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' ! ? 12/8/89 Plant shutdown with reactor coolant temperature below -- , 212 degrees F was achieved at 4:50 a.m.
During plant cooldown, i the "A" isolation condenser condensate return valve, V-14-34, ' did not fully open when cycled at 238 degrees F.
The "A" isolation condenser was declared inoperable.
, 12/9/89 "A" isolation condenser vent valve, V-14-20, had an -- intermittent " closed" indication. The electricians' ! troubleshooting showed that the limit switch was loose.
12/10/89 A Reactor Manual Control System relay, relay 4K6, i -- , located in the 4F panel failed and caused a fire in the control room. Details of this event are described in paragraph 5.0.
' 12/14/89 The licensee commenced a reactor startup at 8:51 p.m.
-- prior to the startup, the "A" isolation condenser was declared , ' operable.
Reactor criticality was attained at 10:27 p.m.
' While cycling the isolation condenser condensate return valves, the "A" isolation condenser vent valve, V-14-20, showed double , indication. V-14-20 was declared inoperable; however, the
1 solation condenser was still considered operable. Technical , ' specifications require that if V-14-20 is inoperable, the affected containment penetration must be isolated by use of at least one closed manual valve or blind flange within 4 hours.
i The manual vent line isolation valve, V-14-6, was shut within 4 hours.
Reactor startup recommenced.
12/15/89 While cycling the "B" isolation condenser steam valve, -- V-14-33, the motor fuse blew. Technical specifications require that V-14-33 must be made operable within 4 hours or the
affected penetration isolated.
The tuse was replaced within 4 . ' hours, and the valve was considered operable.
, < The Control Rod Drive (CRD) rod withdrawal / insert switch would not spring back to the mid position after operation. The licensae identified a broken spring in the switch. The spring was replaced.
The main generator was placed on line at. 7:47 p.m.
12/17/89 Because intake levels were close to the level which -- would require an Unusual Event to be declared, the power ascension was halted.
Reactor power was 76%. ' - ' ' .
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, L 12/18/89 The sample line to the High Range Radioactive Noble -- Gas Effluent Monitor became testricted. The restriction resulted from a portion of the insulation which fell off to-cause the line to freeze.
The licensee had submitted a Technical Specification Change Request which requires submitting L a special report to the NRC if the system is out of service for greater than seven days.
Details of this event are described in paragraph 11.0.
12/19/89 The licensee recommenced reactor power ascension.
-- Reactor power reached 100% power later in the day.
The High Range Radioactive Noble Gas Effluent Monitor was returned to service.
12/22/89 An Unusual Event (UE) was declared as a result of low -- intake water level.
12/24/89 After the intake water level recovered above the UE -- level and the adequate margin above the action level was attained, the UE was terminated.
12/28/89 The Reactor Water Cleanup System (RWCU) isolated when -- a maintenance person inadvertently dropped a wrench on the Standby Liquid Control System flow switch., Details of this event are described in paragraph 9.0, Reactor power was reduced to 93% to return the RWCU system back to service.
Reactor power was returned to 100%. 1/3/90 An Unusual Event (UE) was declared as a result of low -- intake water level at 9:34 a.m.
At 6:00 p.m. after the intake water level recovered above the UE level and the adequate margin
above the action level was attained, the UE was terminated.
, 1/4/90 No. 2 service water pump was removed from service to -- facilitate the replacement of the discharge check valve. This maintenance requires the discharge pressure gauge to be
isolated. No. 2 service water discharge pressure gauge was declared inoperable.
Technical specifications allow continued i plant operations for 30 days with this gauge out of service, 1/5/90 The Reactor Manual Control system was tagged out of t -- ) service to replace the CRD rod withdrawal / insert switch. The , licensee declared all control rods inoperable to facilitate this maintenance.
Technical specifications require the plant to be , ' ~ in cold shutdown within 30 hours with all control rods inoperable. The switch was replaced in approximately one hour, and the control rods declared operable.
The technical ! specification action statement was terminated. The licensee did ! not change reactor power, l !
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1.2 Control Room Tours , Routine tours of the control room were conducted by the inspectors ' during which time the following documents were reviewed: Control Room and Group Shift Supervisor's Logs; -- Technical Specification Log; -- s Control Room and Shift Supervisor's Turnover Check Lists; -- Reactor Building and Turbine Building Tour Sheets;
-- Equipment Control Logs; -- Standing Orders; and, -- Operational Memos and Directives.
-- ! No unacceptable conditions were identified.
1.3 Facility Tours ! Routine tours of the facility were conducted by the inspectors to make an assessment of the equipment conditions, per.sonnel safety, and procedural adherence and regulatory requirements. The following areas were among those inspected: Turbine Building -- Vital Switchgear Rooms -- Cable Spreading Room -- Diesel Generator Building -- Reactor Building -- Intake Area -- The following additional items were observed or verified: a.
Fire Protection: i Randomly selected fire extinguishers were accessible and -- inspected on schedule.
Fire doors were unobstructed and in their proper position.
-- Ignition sources and combustible materials were controlled -- in accordance with the licensee's approved procedures.
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Appropriate fire watches or fire patrols were stationed -- i when equipment was out of service.
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Equipment Control:
Jumper and equipment mark-ups did not conflict with -- technical specification requirements.
- Conditions requiring the use of jumpers received the prompt --
attention of the licensee, c.
Vital Instrumentation: Selected instruments appeared functional and demonstrated -- parameters within Technical Specification Limiting Conditions for Operation.
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Housekeeping: . Plent housekeeping and cleanliness were in accordance with -- approved licensee programs.
2.0 C_o,ndenser Vacuum Transient . On December 7,1989, an operator-initiated transient caused the indicated "B" condenser vacuum to drop below 23 inches Hg for approximately 50 seconds. Although the specified scram setpoint for low condenser vacuum , was 23 inches Hg, no automatic reactor scram occurred. Operator action was taken to recover vacuum in the condenser.
No manual scram was initiated by the operators when the vacuum fell below 23 inches Hg (indicated).
The main condenser consists of three condenser sections which are l connected by 48-inch diameter pipes to help equalize vacuum between each l condenser. The condensers are cooled by circulating water.
Circulating l-water to each condenser is further divided into two sections, a North section and a South section. During normal operation, each condenser has circulating water entering two separate inlet water boxes and discharges out to the discharge tunnel.
During the daily backwashing evolution, the i circulating water system valves are manipulated to direct circulating ' water discharged from one section of a condenser back through the tubes of the other section.
Reversing the circulating water flow through the one (. section increases the circulating water temperature.
This evolution is ) performed to heat up the condenser tubes to help remove biological growth ' and reduce fouling.
The transient was initiated by a control room operator (CRO) when he was performing a daily backwashing evolution on the "B" condenser.
The configuration of the "B" condenser however was off normal.
The "B" North condenser was isolated and drained because of high conductivity problem r!' ! L c'
. L e s Although the CR0 knew that the "B" North condenser was isolated, he erroneously placed the "B" South condenser in a backwash configuration.
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The effect of this action was a loss of cooling water to the "B" condenser. The CR0 immediately recognized his error and directed an electrician to open the breakers for the inlet and outlet valves of the "B" South condenser. Valve motion was stopped with the valves in an intermediate position. As the CR0 was attempting to restore cooling water flow, the other CR0s took actions to reduce power and monitor other plant i parameters.
"B" condenser vacuum returned to normal. The transient ended approximately two minutes after it was initiated.
During the transient, several indications were observed by.the operators.
The rate of drop in "B" condenser vacuum was high. The vacuum in the "A" and "C" condensers were minimally effected by the drop in "B" condenser vacuum.
The low condenser vacuum alarm annunciated when the "B" condenser vacuum indicated 22.2 inches Hg.
The specified alarm setpoint was 25 inches Hg.
The actual scram setpoint was 23 inches Hg.
"B" condenser vacuum indicated below 23 inches Hg for approximately 50 seconds.
A minimum of 20.7 inches Hg was indicated on the "B" condenser. Circulating water was fully restored to the "B" South condenser; however, "B" condenser vacuum continued to decreast for a short time before turning.
~ A post trip review group was convened to review the transient. A reactor shutdown was commenced later on December 7, 1989 in order to calibrate the condenser vacuum trip system. The plant was shutdown; and, the reactor temperature was reduced below 212 degrees F on the following day.
An Augment Inspection Team (AIT) was sent from NRC Region I to review the facts and circumstances surrounding this event. The objectives of the AIT were to evaluate operator, plant and management response to this event and to assess the safety significance of the event. The findings and conclusion of the AIT were documented in Inspection Report 50-219/89-81.
3.0 Unusual Event Associated with Low Intake Water Levels On December 4, 1989, December 18, 1989 and January 3, 1990 low intake water levels below the emergency action level (EAL) of -1.0 ft. occurred.
During each of these events, the licensee properly declared an Unusual Event (UE) and appropriately notified the NRC. The licensee's response in each of these events was prompt and correct.
! In general, intake canal water levels have been low during the previous
( several weeks at about 0 ft. Because of the generally low intake water )_ 1evels, the licensee reviewed their Unusual Event EAL of -1.0 ft, considering recent historical data.
Based on this review the licensee elected to implement a change to the Emergency Plan.
This change consisted of changing the Unusual Event EAL from -1.0 ft. to -2.0 ft.
Also, the Alert EAL was changed from -2.0 ft. to -2.5 ft. The licensee discussed these changes with resident inspectors on 1/3/90 prior to implementation.
The inspector concluded the changes were appropriate and did not reduce the effectiveness of the Emergency Pla i O
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NUREG 0610 provides guidelines for EAls, and the suggested UE action level for loss of water is to be the lowest level expected in 50 years.
The-2.0 ft level selected by the licensee is the lowest level reported during the past 10 years. The inspector concluded the use of this level acceptable.
4.0 Inadvertent Movement of Two Control Rods On December 16, 1989, during power ascension, the control room operator (CRO) manipulated the control rod select switches in such a manner to simultaneously select two control rods.
The two rods selected were rod number 14-27 and 18-27.
Not realizing that two rods were selected, the CR0 inserted a " notch out" signal.
The CR0 very quickly realized that two control rods were simultaneously selected to move.
In response to this indication, the CR0 de-energized rod select power. This action stopped the control rod motion; and, both rods settled at their original positions, rod 14-27 full out at notch 48 and rod 18-27 at notch 12.
No reactor power transient occurred. The CR0 subsequently withdrew control rod 18-27 to noteh 14 to establish a symmetrical pattern with the r other three control rods in that group.
The Control Rod Reactor Manual Control System (RMCS) is designed to select and move only one control rod at a time.
The action of selecting a control rod is designed to automatically deselect the previous control i rod.
Licensee review concluded that this event was a condition outside the design basis and notified the NRC in accordance with 10 CFR 50.72.
Reactor power ascension was halted until a review evaluating plant safety was completed.
Even though this was not a plant trip, the licensee convened its Post Trip Review Group (PTRG) to evaluate this event. The PTRG preliminarily concluded the following: (1) the plant was in a safe condition; (2) that reactor power could be increased with control rods provided a second licensed operator was stationed to verify only one control rod was ' selected; and (3) Plant Engineering should perform a detailed review of the design and operation of the RMCS rod solect switches and the interrupt l.
circuitry.
Also, the following actions were taken: (1) the interrupt time delay was increased from 0.2 to 1.0 second; (2) the procedure for abnormal rod . motion was identified as required reading; and (3) all rod select relays l l were visually inspected and deficient items were repaired.
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f ! Licensee's analysis of the event and the corrective actions were reviewed , with site resident inspectors and Region I managerrent personnel prior to continuing power ascension using control rods.
NRC inspectors reviewed the operator response, plant evaluation and plant corrective actions . associated with this event.
This review included control room logs, - electrical elementary drawing GE 112-C-3658, site Procedure
> 2000-ABN-3200.36, " Abnormal Control Rod Motion," site Updated Final Safety ' Analysis Report, and NUREG-0822 " Integrated Plant Safety Assessment."
The insp(etor concluded that the control room operator actions and response to this event were prompt and correct.
The initial action of
de-energizing rod select power terminated the event.
The timeliness of ' this action prevented any possible reactor power transient. The time frame from the initiation of multiple rod motion until it was terminated was less than 5 seconds. Both affected control rods settled at their original positions.
The operator correctly recognized what initiated this rod motion and promptly secured it. Although a manual reactor scram could have been initiated with more than one control rod moving, the inspector ' , , concluded for this event that action would have initiated an unnecessary plant transient.
No unacceptable conditions were identified in control room operator response.
The inspector's review of the updated Final Safety Analysis Report con-cluded that the simultaneous movement of two control rods was outside the design basis of the plant.
The inspector concluded, however, that the actual safety significance of this event was low for the following reasons: (1) with one of the affected control rods full out no reactivity transient was initiated, (2) operator response was rapid in terminating *.ie , event in a short time frame and (3) the scram f unction was not affected Also, a review of multiple control rod motion was performed in NUREG N22, paragraph 4.15.
This event is characterized in NUREG-0822 as a low contributor to plant risk.
It was also identified that single failures, the Reactor Manual Control System do not affect the ability of the scram
function.
The inspector concluded that licensee's evaluation of this event was thorough and correctly identified the interrelationship between rod select push buttons which could allow multiple control rod selection.
The
licensee identified that multiple rod select switches must be manipulated simultaneously in order to select more than one control rod.
The inspector reviewed the subsequent CR0 action to move control rod 18-27 to notch 14 to establish a symmetrical rod pattern and concluded that this I action was acceptable.
No unacceptable conditions were identified.
5.0 Relay Fire Control Room Panel On December 10, 1989, relay 4K6 in the Reactor Manual Control System (RMCS) failed. This relay failure resulted in smoke and flames which were prompt?y extinguished.
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' L Licensee corrective actions included replacing this relay and also two other relays in close proximity which were also potentially affected.
The relay which failed is a General Electric Model CR120 relay.
This - specific relay was originally installed during plant construction.
The licensee is currently performing an evaluation of this model relay in ' order to identify the need for replacement because of aging effects.
, The inspector reviewed the licensee's evaluation and corrective actions associated with this event. No unacceptable conditions were identified.
6.0 Potential Waste Surge Tank Leakage , On December 12, 1989, the licensee observed water coming from the drain line to an abandoned tank, the waste surge tank.
The tank had been abandoned several years ago because its integrity was questionable.
t The licensee considered the event to be a potential unmonitored release because of the possibility that the water which was contaminated was potentially leaking through the bottom of the waste surge tank into the ground. The tank is located within the radiologically controlled area.
, i The sequence of events which led to contaminated water entering the waste surge tank began with problems in the High Purity (HP) System.
The High Purity System consists of two trains.
The system collects low conduct-ivity contaminated water from the reactor plant where it is processed to be re-used in the reactor plant or discharged.
On December 9, 1989, . problems were experienced with the "B" train pump.
The pump was tripping t on low suction pressure. The "A" train could not be us'J because the "A" HP tank was filled with high conductivity water-(high '.hloride content).
' To support continued plant operations, several options v: e ansidered by the licensee to transfer water from the "B" HP tank. I m lit asr-elected , to use the waste collector pump NV-02 to transfer the wattr from.he "B" l HP tank. The waste collector pump has a recirculation line to the waste surge tank.
The tank had been abandoned since 1981. Piping leading to this abandoned tank'was isolated by tagged isolation valves; and, the ' tank's drain which directs any water in the tank into the 1-10 sump was g opened.
During the operation of the waste collector pump, it was noted that the 1-10 sump pump was running excessively. An investigation showed water from the waste surge tank drain valve was draining to the sump.
The recirculation line isolation valves were leaking by.
In response to this event, the licensee conducted a critique of the event.
l The root cause was identified to be inadequate task planning and the ! failure to be cognizant of system status. There was also a lack of l perceived need by Operations management to isolate the waste surge tank since the waste surge tank was already isolated by tagged isolation valves.
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i ! Immediate corrective actions were taken by the licensee. These actions included: (1) immediately stopping the transfer of water from the "B" HP tank (2) inspecting the inside of the waste surge tank for water and sources of inleakage, and (3) sampling of the water passing through the waste surge tank drain. The inspection of the waste surge tank showed that the bottom of the tank was intact except for a crack measuring several inches long.
The licensee took several additional corrective actions.
These actions included: (1) installing and leak testing blank flanges in the pipes ' connected to the waste surge tank to prevent further inadvertent leakage of water through leaking valves, (2) routine monitoring of the waste surge tank drain line and the filter sludge tank by the radwaste operator, and (3) incorporating this critique as required reading.
, The licensee concluded the amount of water which may have leaked through the bottom of the tank, if any, would be small.
The capacity of the drain , was estimated by the licensee to exceed the water leakage into the tank through leaking valves. As a result, no significant amount of water accumulated in the tank. The leakage through the several-inch crack was not quantifiable; but, because no significant accumulation of water in the tank was believed to have occurred . any, was estimated to be very smalI the water leakage into the ground, if In 1981, the waste system tank was abandoned because of water leakage through the tank's bottom into the ground.
The leakage resulted in the soil beneath and around the tank to be contaminated. The licensee has several well monitors on site to detect any potential migration of the contamination, The information collected by the well monitors are
recorded by the licensee in the Radiological Effluent Monitoring Report.
- Migration is believed to be unlikely because of the insolubility of cobalt and its affinity for sand. No migration has been detected by the well
monitors.
- The inspector reviewed the circumstances surrounding the event and the corrective actions. The inspection concluded that the leakage from the waste surge tank, if any, would be small. The corrective actions appear to - appropriately address the identified weaknesses.
L The inspector had no further questions.
7.0 ' Scram Air Header Pressure Value Resident inspectors reviewed the licensee's response, evaluation and l-corrective actions associated with the setting and controlling of scram ' air header pressure.
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e r F Licensee personnel questioned the operation of the Control Air System which was supplying air at approximately 95 psig to the reactor scram
valves.
This concern was documented in a Deviation Report.
t " The preliminary licensee review could not identify the design basis for scram air header pressure valve. Current system operating procedures specified a band of 75-100 psia, and no value was identified in the > , Updated Final Safety Analysis Report. The pressure regulating valves < , , supplying control air to the scram valves were reset to control this pressure between 82 and 85 psig, i-Since increasing this pressure would tend to increase the amount of time until the scram valves would open, the inspector questioned what pressure existed during the most recent scram time testing and alternate rod > insertion testing.
The pressure for the alternate rod insertion testing was documented to be between 90-95 psig.
The pressure existing during the most recent scram time testing could not be verified. The inspector concluded, however, that it is likely that this pressure was also between 90-95 psig.
' The inspector concluded that because the acceptance criteria for scram , times and the acceptance criteria for alternate rod injection were met at the higher scram air header pressure valve, that plant safety was not
adversely affected.
' The inspector further concluded that the questioning ittitude of site personnel and their efforts to attain resolution to this question resulted in an improvement in the control of scram air header pressure. Also, this appeared to be an effective use of the Deviation Report.
Even though no , clear criterion was found in station procedures or the FSAR, a Deviation Report was still initiated and documented and resolved the question. No unacceptable conditions were identified.
lI 8.0 - Control Rod Drives (CRD) Uncoupling Rod Dimensions l > A review was conducted by the inspector to determine if the critical dimension for the control rod drive (CRD) uncoupling rod was properly controlled. This review was conducted based on two events where a control rod blade (CRB) became uncoupled and several events where CRD high L temperaturo alarms were bypassed because of high temperature conditions.
The CRD uncoupling rod allows for cooling to the control rod when the rod ' ' is at position 48.
It is required because at position 48 the normal ' cooling flow path is blocked. The cooling water flow path when the CRD is at position 48 occurs when the uncoupling rod pushes up on the spud which is connected to a valve. The valve opens, allowing a path for cooling water flow.
If the rod is too long and the spud is lifted too much, rod uncoupling can occur.
If the rod is too short and the spud is not lifted , enough, inadequate cooling flow can resul F A . j ' e l
j i The encoupling events are documented in Inspection Report 50-219/89-28 and Inspe: tion Report 50-219/88-03. The event in 1988 involved CRD 30-23.
, During the last refueling outage the CRD was inspected. The filter on j which the uncoupling rod rests was dirty and slightly cocked. The
uncoupling of this rod when performing a coupling check was attributed to > this finding.
In 1989, CRD 06-23 also uncoupled during uncoupling checks.
The CRD and the CRB, however, were in place since 1979. This uncoupling
was observed only during the present operating cycle. As a result, the ' inspector concluded that the cause of this uncoupling is not likely to be ' , improper dimension of the uncoupling rod, , At the time of the inspection, two control rod high temperature alarms
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< ! were bypassed. The inspector observed, however, that the rods were not at position 48 and therefore the improper critical dimension of the uncoupling rod was not a contributor.
The inspector reviewed the licensee's Control Rod Rebuilding procedure, Station Procedure 717.1.008. The procedure was reviewed against the vendor's control rod drive maintenance instructions, GEK-94891.
The inspector concluded that the licensee's procedure adequately incorporated the measurements of this critical dimension as recommended by the vendor.
During the review the inspector noted that Standing Order No. 40, + " Bypassing of Control Rod Drive High Temperature Alarms," was not being
strictly adhered so.
The standing order stated that the bypass for the alarms should be removed if two consecutive readings (readings are performed weekly) indicate the temperature is less than the alar'n setpoint. The data sheets for the standing order showed that the CRDs have continued to be bypassed after meeting the above criteria.
The , licensee has since unbypassed the alarms which were below the setpoint and
is reviewing the standing order requirements.
' Overall, the inspector concluded that the licensee's procedure for rebuilding CRD's adequately addresses the measurement of critical dimen- , sions when required and incorporates the recormendations of the vendor manual.
The inspector concluded that none of these events were a result of an incorrect uncoupling rod dimension.
No unacceptable conditions were identified.
, l 9.0 Torus Water Level Increase On September 29, 1989, during the performance of a surveillance on the Standby Liquid Control (SLC) system, a wrench was inadvertently dropped on .- ' the system flow sensor switch and caused it to actuate. The switch l provides an input to isolate the Reactor Water Cleanup (RWCU) system in the event the SLC system initiated. As designed, when the switch actuated, the RWCU system isolated.
Reactor power was reduced to 92.5% in , order to place the RWCU system back into service.
The licensee generated a Deviation Report on the event.
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The RWCU system relief valve lifted when the system isolated. The water from this valve is directed into the torus.
The licensee believed that the relief valve did not fully seat after the transient.
As a result of this deficiency, water leaking past the relief valve has caused torus water level to increase.
The drywell unidentified (VID) leakage is determined by measuring the water leakage into the 1-8 sump.
In addition to this measurement, the torus water level is also monitored. An increase in torus level is calculated into drywell UID leakage because the water entering the torus can potentially come from the drywell through the downcomers. The licensee has calculated that a 0.1 inch per day increase in torus water level corresponds to a 0.41 gpm leak rate.
The licensee attempted to reset the relief valve by lowering RWCU system pressure.
This action reduced the relief valve leakage.
The condition of the relief valve was evaluated to be acceptable for continued operation; however, small amounts of water leaking by the relief valve continued to cause torus water level to increase. The Plant Analysis Group. reviewed the torus level increase for a 12-day period and estimated an average level increase of 0.05 inch per day. This level increase corresponds to a leak rate of 0.2 gpm.
The inspector concluded that the licensee's evaluation and disposition of the increasing torus water level was appropriate.
The drywell leakage into the 1-8 sump has remained relatively constant at 1.84 gpm throughout this period.
No unacceptable conditions were identified.
10.0 Defective Respirators In November 1989, the licensee informed the resident inspectors that two respirators were found defective. After the respirators were removed from their bags, the mouthpieces fell off.
The band which straps the mouthpiece to the respirator was extremely loose.
The licensee reviewed this event to determine the cause for the defective respirators. The cause, however, was not determined.
The licensee stated that these two respirator defects were an isolated event. Additionally, the licensee has increased their inspection of the respirators.
The licensee has evaluated the safety significance of this event as minimal.
The nature of the defects were such thst it would be obvious to the user that the respirator could not be used.
Personnel are trained to inspect and perform a seal test of the respirators prior to usage.
The licensee believed that because of the nature of the defect it would be inconceivable for these respirators to pass the worker's inspection and seal test prior to use,
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. The inspector concluded that the safety significance of these specific
defective two respirators were small. Although the licensee's efforts to determine a root cause were unsuccessful, the licensee's actions to determine the cause and take preventative measurements were appropriate.
The inspector had no further questions.
11.0 Radioactive Gas Effluent Monitoring System (RAGEMS) Out of Service On December 18, 1989, after observing the flow in the RAGEM system reduced, the licensee declared the system inoperable.
Technical specifications allow continued plant operation with this system out of service provided grab samples are obtained. This system continuously samples site radio-active gas emissions from the stack. The suspected problem was the collection and subsequent freezing of moisture in the sample line from the stack.
Restrictions in this line would preclude manual grab samples directly from the stack.
In order to meet technical specification requirements the licensee identified locations for all inputs to the stack at which to collect grab samples. The inspector reviewed there plans and concluded that technical specification requirements were satisfied.
The inspector also discussed with the Emergency Preparedness (EP) Man ger what actions could be implemented in the event of an emergency.
It was - stated that plant conditions would form the basis for protective action recommendations and that in the event of an actual release it could be verified using field monitoring teams.
. On December 19, 1989 stack RAGEMS was returned to service after thawing of the san"le line end reinsta11ation of line insulation.
No unacceptable conditiori were identified.
12.0 Monthly 1%t m c ice Observation On January. Iv90, 1he inspector observed maintenance performed on the C2 battery chi.rger.
The safety related battery C is provided with two l battery chargers, namely C1 and C2. At least one of these battery chargers is required to be in service to keep the distribution center bus
C energized and battery C charged.
However, when charger C2 was put in service, the control room trouble alarm for battery charger C2 would come l in.
The licensee's troubleshooting indicated the probable cause to be an inability of a CFA alarm card to operate properly at the low voltages normally seen by the charger.
L The licensee intends to install a new type of alarm card via a f.
mini-modification during the 13R refueling outage. The alarm setting of I this new card will be compatible with the low operating current of the battery charger. As an interim measure a maintenance job order was prepared to replace the alarm card. The inspector verified required i i equipment tagging was in place, the required approvals were obtained and
' the control room operators were informed'and communicated with as required during installation of the replacement card.
The part number of the new card did not match the part number identified in the vendor manual. The < l
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part number of the newly installed card, however, matched that suggested ' in a vendor letter dated March 2,1988. The licensee will revise the affected vendor manual. After installation of the card, the licensee verified proper operation of the alarm. The inspector did not have any further questions.
13.0 Enforcement Conference An Enforcement Conference was held at the NRC Region I office with GPU management on December 5, 1989 to discuss the circumstances surrounding the mispositioned DC knifeswitch and the operation of containment spray and emergency service water systems without supporting documentation.
These events were discussed in Inspection Report 50-219/89-23 and Safety System Functional Inspection Report 50-219/89-80 respectively. A list of attendees is enclosed in Attachment II.
The licensee presented a description of the events, corrective actions taken and their evaluation of safety significance. Mitigating factors and clarification of facts were discussed. A summary of this presentation is enclosed in Attachment III.
NRC assessment of the issues discussed will be trant.mitted by letter to the licensee.
. 14.0 Safeguards Meeting A safeguards meeting was htid at the NRC Region I office with GPU representatives on January 3, 1990.
The purpose of the meeting was to discuss certain concerns raised by the Safeguard Regulatory Effectiveness Review (RER) which was conducted at Oyster Creek on July 18-22, 1988.
The licensee presented their intended resolution of RER concerns and their schedule for completien of the resolution.
The NRC requested that the noosed changes be submitted to the NRC in writing for review prior to <lerentation. A list of meeting attendees is enclosed in Attachment IV.
l 15.0,Previously Opened _ Items (Closed) Open Item 86-25-01.
Inspection Report 50-219/86-25 documented an event during a refueling outage in which a control rod blade (CRB)
became detached from the control rod latching tool and struck the top grid ' of the core. At the time of the event, no fuel was in the core. The control rod blade was damaged and was replaced by a new blade.
No other I damage was observed.
( During the inspection in 1986, the licensee had not completed their review / of the dropped blade incident. The licensee stated that the control rod L latching tool would not be used until the cause of the event was identified and corrected. Additionally, the licensee stated that the appropriateness of incorporating additional cautions and prerequisites in , i their control rod blade handling procedures would be reviewed.
The item
was left open pending review of licensee's corrective actions.
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! The licensee's review could not conclusively determine the cause of the event. A critique was held with operations personnel and concluded that the cause of the event was not personnel error.
The pessibility that the grapple hook was not engaged to the lifting bail and that the unlatching-actuator was actually lifting the control rod blade was considered the likely cause.
The licensee, however, could not positively show that this was the cause.
' A vendor information letter, SIL No. 454, was issued in 1987 which i addressed potential control rod latch tool malfunctions. The SIL refers to an incident at another plant in which a blade was dropped because the o grapple hook failed to latch onto the lifting bail and the D ring latch mechanism carried the entire weight of the CRB.
The vendor recommended several actions to take with regard to this potential problem. These actions included inspecting specified components of the control rod latch tool, maintaining the tool at regular intervals, performing operational checks prior to use and confirming the latch tool is in firm contact with the control rod blade prior to latching.
The licensee implemented the recommendations of '.he SIL. The procedures . for handling the control rod blade were reviewed and evaluated to be adequate. After completion of the required inspections, the control rod latching tool was determined operable.
' During the 12R outage the tool was used only to unlatch the control rod blade from the drive mechanism. The control rod grapple tool was used to move the CRBs.
The grapple tool does not have a D rig latch tool which can lif t the CRB when the grapple hook is not latched.
The licensee considers it good operating practice to use the grapple tool to move CRBs versus the latch tool.
The licensee is taking action to incorporate the philosophy of-using the grapple tool as the preferred lifting tool in their procedure.
Based upon the licensee's completion of their review, implementation of SIL No. 454 and current operating practices, this item is closed.
'(Closed) Unresolved Item 86-37-05.
Inspection Report 50-219/86-37 documented a review of surveillance requirements for the emergency diesel generator (EDG). The EDG 2000 hour rating had recently been increased to '2750 KW.
During the review, the licensee was unable to produce any dynamic test results on the diesel generator to assure its capability to perform at the new rating and to simulate loading representative of the )- accident conditions.
The item was left unresolved pending review of the licensee's records on dynamic test of the diesel generators at the increased capacity.
The inspector reviewed Surveillance Procedure 636.2.001, " Diesel Generator Automatic Actuation Test." This test is conducted every refueling outage and simulates dynamic conditions during an accident.
Signals are simulated to automatically start the EDG, strip loads from the vital buses and sequence vital load p l
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The inspector observed the performance of the last ED3 automatic actuation E test. During this testing, the other diesel was simulated to be ! inoperable. The loads were observed to sequence on to the 4160 volt bus properly.
It was observed during the test that some molded case breakers did not trip as designed.
This discrepancy was discussed and reviewed in Inspection Report 50-219/89-14.
The EDG, however, performed its function even though it carried additional loads.
The inspector noted that the core spray pumps and booster pumps operated at rated flow during the test.
Technical Functions have stated that the pumps would go to runout in the design basis accident.
The FSAR shows that there is a 60 KW and 17 KW higher loads for the core spray pump and booster pump respectively in a runout condition.
The inspector reviewed the licensee's analysis which showed that the diesel was capable of handling the accident loading. Additionally, a static test in which the EDG is operated at 2750 KW for ) hour is performed weekly.
Based on the review of the licensee's analysis and the performance of the - static and dynamic tests, this item is closed.
> t (Closed) Unresolved Item 87-01-01.
Spurious operation of an electromatic relief valve (EMRV) during a contro,,1 room fire.
This item identified the concern that in the event of a control room fire and control room evacuation, and because of the routing of EMRV control cable, there was a possibility of two shorts occurring. This could result in the inadvertent opening on an EMRV and an uncontrolled blowdown of the reactor. This item was unresolved pending licensee evaluation of addressing this problem by pulling control circuit fuses located outside the control room for EMRVs.
Licensee review and analysis concluded that pulling the EMRV control circuit fuses located in the 460 volt room was an appropriate measure to counteract spurious EMRV operation.
Station Abnormal Procedure 2000-ABN-3200.30 was revised to include the necessary steps directing operators to pull EMRV fuses.
l The inspector reviewed Station Procedure 2000-ABN-3200.30, " Control Room l Evacuation." This procedure directs control room operators after a control room evacuation to pull EMRVs' fuses to prevent spurious opening l if three conditions are met; (1) there is a fire in the control room ! resulting in control room evacuation, (2) the remote shutdown panel - has been actuated and pressure / level control has been established, or it is suspected that an EMRV has spuriously actuated, and (3) a senior
reactor operator on shift approves pulling the fuses.
The procedure specified the fuse number and location.
Based on the licensee's corrective action to implement procedural guidance - to pull EMRV fuses in the event of a control room fire and control room evacuation, this item is closed.
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(0 pen) Unresolved Item 87-04-02. Deficiencies in containment spray logic.
This item addressed two weaknesses in the containment spray system logic.
The first was the possibility of an inadvertent drywell spray, and the second was the inability to establish torus pool cooling during conditions of low reactor water level.
< The licensee addressed the concern of inadvertent spray in the drywell by performing a worst case analysis. The results of this analysis show that i containment integrity is maintained under the worst conditions of inadvertent drywell spray.
To address the inability to establish torus pool cooling during conditions ' of low reactor water level, the licensee implemented written guidance to the operators. This provides written instruction to direct the operators to defeat the low-low reactor water level signal during conditions when torus pool cooling is needed. NRC inspection report 50-219/89-09 reviewed , the actions specified to allow establishment of torus pool cooling. This report concluded the corrective actions were adequate and provided assurance that torus pool cooling could be established by defeating the interlock.
In addition, the NRC performed a safety system functional inspection of the containment spray system, and specifically reviewed the system logic configuration. This item remains open pending further NRC review.
(Closed) Unresolved Item 87-05-02. Operations and Security interface during radiological emergencies.
, This item addressed weaknesses in the interface between safeguards and operational safety during radiological emergencies.
The following specific concerns were noted: l No triggering mechanism to suspect sabotage; -- No guidelines to verify the security of other safety systems; and, -- No procedures specifying the type of countermeasures to consider.
-- , As corrective action, the licensee incorporated written guidelines to address Operation and Security interfaces.
These guidelines are contained i in Emergency Plan Implementing Procedure EPIP 6430-IMP-1300.42, Rev. 1.
Inspectors reviewed the requirements specified in the above procedure and concluded they provide adequate guidance to address the weaknesses identified between Operations and Security.
Based on the incorporation of these guidelines into an improved procedure, this item is closed.
(Closed) Unresolved Item 89-04-02. This item was left open pending licensee's corrective action on environmental qualification of two breakers associated with valves V-37-11 and V-5-16 ' ' . ,
On January 13, 1989, the licensee identified that certain circuit breakers were replaced during the 11R outage without implementing environmental qualification requirements. The licensee's review indicated two breakers and two fuses were installed without the required qualification documenta-tion. To evaluate the safe.y significance of previous plant operation with unqualified components, the licensee performed a similarity analysis of the removed components as compared to qualified components. The analysis demonstrated that the electrical components were qualifiable.
These components were replaced during the 12R outage with qualified components.
The licensee also updated the component data in the GMS-2 system for breakers in the environmentally qualified MCCs (total of 7), and added the EQ system component evaluation work (SCEW) sheet numbers. Thus the breakers located inside the environmentally qualified MCOs are now identified as EQ components with the related information in the SCEW sheet.
Lack of adequate documentation to demonstrate environmental qualification of the subject components during operation subsequent to 11R outage is a violati:n of the 10 CFR 50.49 requirements.
Based on licensee's identification and prompt replacement of the breakers in question and - documentation that the replaced breakers were qualifiable, this violation is not being cited. The criteria specified in Section V.G of the Enforcement Policy was satisfied because: , The deficiency was identified by the licensee; -- It fits in severity level IV or V; -- No reporting was required, as the components were determined -- qualifiable; The deficient components were promptly replaced; and, -- It was not a violation that could have been prevented by licensee's -- previous corrective actions.
(NCV 50-219/89-29-01) The inspector did not have any other concerns.
This item is closed.
(0 pen) Unresolved Item 86-37-01.
Inspection Report 50-219/86-37 documented potential seismic interference between Motor Control Center (MCC) 1821 and Unit substation (US$) 1B2. As part of 10 CFR 50 Appendix R I.
modifications, MCC 1B21 was added in "B" 480 V room.
The MCC was positioned next to USS 1B2 with a gap less than 1/4 inches.
The item was left unresolved pending evaluation of the gap to confirm compliance with seismic performance requirements.
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The licensee issued a licensing action item (LAI) to Technical Functions to address the seismic issue. An LAI is an internal tracking system used to track issues. Technical Functions' response to this issue was to provide documentation to show that both the MCC and US$ were seismically qualified.
Impe11 Corporation Report No. 02-0370-1378 (Source 10292) and Northern Corporation Report No. GPU -1712R showed that both structures were rigid in the side to side direction.
The licensee concluded that because both structures were rigid in the side to side direction, no potential existed for seismic interference between MCC IB21 and USS 182.
The inspector reviewed the licensee's conclusion that both structures will not interfere with each other because they are rigid. The logic of the licensee's conclusion was not apparent to the inspector. Although the structure in the side to side direction is rigid, some motion is still expected.
The impact of this motion on the seismic qualification should be reviewed. This item will remain unresolved pending further licensee review of the potential for seismic interference.
(0 pen) Unresolved Item 87-04-01.
This item was lef t open pending licensee's determination as to the need for the offgas sample pump when the plant is not in startup or run modes, and submittal of a revision to paragraph I of Table 3.1.1 of the Oyster Creek Technical Specifications.
The licensee is currently preparing the technical specification change submittal.
This item will be reviewed and resolved pending submittal of this change request.
(0 pen) Notice of Violation 88-02-01. This violation against the requirements of 10 CFR 50.59(a) involved a long term operation of the Oyster Creek plant with the reactor building heating system out of service without any compensatory measures and without performing a written safety evaluation. As a result of this, several instrument lines were found frozen in the reactor building during January 1988. The Notice of Violation indicated that the licensee delayed the needed repair to the heating system for a period of about two years, thereby effectively making ' a change to the facility.
The licensee did not concur with the violation against 50.59.
Their response indicated that they did not intend to make any change to the system design and that nothing in the design basis required that reactor building temperature be maintained at any minimum temperature.
l In order to evaluate licensee's position the inspector reviewed the Update , ) Final Safety Analysis Report (UFSAR) and the plant technical specification which were found to contain the following:
UFSAR in Section 9.4.2.1 states that the reactor building HVAC system -- is designed to cope with a minimum drywell temperature of 10 degrees F.
The flow diagram 9.4.2A indicates a heating coil is provided in the outside air supply line, which increases this minimum outside
,. . , 21-temperature to 50 degrees F.
The UFSAR also indicates that for about 2.5 percent of the time, the outside air temperature will be below this minimum 10 degrees F number.
UFSAR in Table 3.8.13 lists the allowable stresses for drywell -- concrete shield wall. A 55 degree F maximum temperature gradient across the shield wall was noted in the table.
UFSAR in chapter 3.8, under general design and analysis iaformation, -- while describing the analysis for acceptability of the drywell liner and concrete shield wall air gap, assumed that the ambient temperature in the reactor building is never permitted to drop below 60 degrees F.
The Oyster Creek technical specification in Section 5.3, " Design - Features for Auxiliary Equipment," indicates that the spent fuel pool structural analysis accommodates a worst case loading due to thermal gradient to be from a 60 degree F differential temperature across the pool floor and walls during normal operation. This is due to a 125 degree F maximum temperature in the fuel pool and a 65 degree F lowest temperature in the reactor building.
The structural analysis of the spent fuel pool incorporated this worst case loading, together - with other loads, including a dynamic load from the cask drop accident.
' From the above references it could be conc 1'uded that although the ambient' outside temperature is expected to be below the design minimum intake. air temperature condition f r the reactor building HVAC system for 2.5*4 of the time, various design r.alysis in the UFSAR did assume certain minimum temperatures in the 'eact_c building.
This includes the FSAR chapter 15, spent fuel cask drop M ssi, results of which could potentially be adversely affected if t' e uc r se thermal gradient across the fuel pool floor assumed in the fuei pool h. ding analysis is allowed to be exceeded.
Thus the licensee by allow:ng the reactor building heating system to remain out of service for an extended period of time of about 2 years, and by not providing any alternate means of maintaining this function had effectively made a change to the facility whereby the reactor building temperature was allowed to go below the minimum temperature assumed in the UFSAR analysis. As a result of the low temperatures in the reactor building certain instrument lines were found frozen on January 6,1988.- The inspector reviewed the licansee's corrective action in response to the incident.
The licensee has prepared structural analysis to establish the > effect of low reactor building temperatures to the drywell shield wall.
Engineering evaluation of the reactor building HVAC system indicated actions to be taken when outside temperature drops below a certain number.
The licensee also evaluated the structural and equipment temperature limitations to establish a minimum reactor building temperature of 40 degrees F.
The operating procedure for the reactor building HVAC system was revised to incorporate actions to be taken during low temperature conditions, including periodic monitoring, isolation of the reactor
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i building normal HVAC system and initiation of the standby gas treatment system, and use of portable heaters, etc.
The inspector will continue to review the licensee's corrective action, winterization plan, and measures established to prevent low temperature conditions in sensitive areas like , the battery room and emergency diesel greater building.
This item will
remain open pending further review as stated above, and a determination on the applicability of CFR 50.59 criteria, B(0 pen)Notice of Violation 88-02-02.
Station Procedure 329, " Reactor i uilding Heating, Cooling and Ventilation System," indicated that a reactor building temperature indicator was located on control room panel
11R.
This temperature indicator, however, was never installed.
The plant operated in violation of the procedure for nearly 20 years, and periodic review of the procedure performed following the station procedure control requirements failed to identify this discrepancy.
In response to the Notice of Violation the licensee stated that following identification of this, all 200 and 300 series system operating procedures were reviewed by a group of control room operators and their supervisors.
, l The objective was to identify equipment that was referenced in these procedures but did not exist or limits identified in the procedure that were not appropriate. This review identified two instances related to , limits and two instances related to equipment. However, the licensee could not produce any documentation of this review or its findings.
The inspector interviewed four of the five personnel involved in the team.
From this interview it appeared that a review of these procedures was undertaken and several discrepancies related to equipment and limit were identified.
The licensee could not generate any documentation on how these discrepancies were resolved.
Station Procedure 107 indicated that during the periodic review of procedures, the reviewer should contact a " user" of the procedure for t feedback on adequacy of the procedure and document the feedback and ' comments. The licensee indicated in the response to the notice of violation that additional guidance to reviewers would be included in Procedure 107 to reinforce the need to obtain user feedback during biennial review of procedures.
In order to determine how " user feedback" process is utilized in the periodic procedure review the inspector contacted various licensee personnel.
It appeared that documentation of user feedback is not considered as an absolute requirement, although a requirement to contact a user for feedback is generally understood and followed.
Informality of the user review was of some concern to the inspector. Also, there appeared to be no change made to Procedure 107 yet to address the-commitment to provide additional guidance to the reviewers to reinforce the need to obtain user feedback.
This item will remain open pending further review.
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) i 16.0 Inspection Hours Summary Inspection consisted of 230 direct inspection hours out of a total of 401 _ inspector hours on site. Thirty-eight of these direct inspection hours ' were performed during backshift periods, and 19 of these hours were deep backshift inspection.
17.0 Persons Contacted / Exit Meetino Inspection observations and findings were discussed periodically with applicable licensee employee, supervisory, and management personnel during the inspection period, and a summary of findings was also discussed at the conclusion of the inspection (see Appendix I).
No , proprietary information was covered within the scope of the inspection.
No written material was given to the licensee during the inspection , period, s )
.; . ATTACHMENT I Personnel Contacted Licensee Personnel F. Aller, Plant Materiel R. Barrett, Plant Operations Director
- K Bass, Manager, Materiel Assessment R. Brown, Radwaste Operations Manager D. Brittner, Control Room Operator
- G. Busch, Licensing Manager P. Fischler, Electrical Supervisor
- E.
Fitzpatrick, Vice President & Director
- V Foglia, Technical Functions Manager J. Freeman, Plant Operations
- S. Fuller, OPS, QA Mgr.
L. Garibian, Technical Functions R. Gayley, GE Operations Engineer G. Hutton, Group Shift Supervisor M. Husain, Plant Engineering D. Jones, Electrical Engineering C. Mengel, Human Resources W. Muelheisen, Support Superintendent K. Mulligan, Plant Operations , , L, Munzing, Plant Engirseering R. Murdock, I & C. Engineering S. Narayan, Electrical Engineer 0. Perez, Plant Engineering
- D. Ranft, Plant Engineering S. Reininghaus, Control Room Operator
- J. Rogers, Licensing
. G. Sadaukas, EP & I
- P. Sca11on, Plant Operations Manager T. Sensue, Operations M. Slobodein, Rad Con Director W. Stewart, Safety Review R. Sullivan, Emergency Preparedness Manager S. Tummine111. Eng. Mechanics J. Vaccaro, Plant Ops J. Voug11tois, Env. Control E. Weibrecht, Plant Ops, Control Room K. Wolf, Rad Engineering Mgr.
NRC Personnel
- M. Danerjee E. Collins
- D.
Lew Denotes attendance at exit meeting.
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, l l ATTACHMENT II Enforcement Conference Meeting Attendees GPU Personnel R. Barrett, Plant Operations Director G. Busch, Licensing Manager J. Devine, Technical Functions Director E. Fitzpatrick, Vice President & Director 'o D. Jerko, Engineer, Licensing M. Laggart, Licensing & Reg. Affairs J. Logatto, Technical Functions A. Rone, Plant Engineering Director D. Slear, Plant Systems Director P. Smith, Technical Functions J. Sullivan, Emergency Preparedness Manager N. Trikouros, Manager SA & PC NRC Personnel M. Banerjee, Resident Inspector, Oyster Creek l K. Christopher, Enforcement Specialist E. Collins, Sr. Resident Inspector, Oyster Creek C Cowgill, DRP, Branch 4B, Section Chief J. Durr, Chief, Engineering Branch, DRS P. Eapen, Chief, Special Test Programs Section, EB, DRS H. Gray, Senior Reactor Engineer, MPS, EB, DRS W. Hodges, Director, Division of Reactor Safety W. Johnston, Deputy Director, Division of Reactor Safety i W. Kane, Director, Division of Reactor Projects D. Lew, Resident Inspector, Oyster Creek J. Strosnider, Chief, MPS, Engineering Branch, DRS E. Wenzinger, Chief, Projects Branch 4, DRP , !
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ATIACIMNT III j IR 89-29 I I - . i . . . OYSTER CREEK NUCLEAR GENERATING STATION I U I I
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I: - - AGENDA I I.
IN'IRODUCTION i II.
USS 182 CONTROL POWER SWITCH MISALIGNMENT i (INSPECTION 50 219/89 23) I , A.
CHRONOLOGY OF EVENTS B.
SAFETY SIGNIFICANCE / CONCLUSIONS I C.
ENFORCEMENTAPPLICABILITY I . . . III.
SSFI (INSPECTION 50 219/8940)
A.
CHRONOLOGY OF EVENTS . . I . L B.
SAFETY SIGNIFICANCE - y c CONCLUSIONS I ' I I . .. - . - - - -
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I - USS IB2 CONTROL POWER SWITCH MISALIGNMENT - , I ' (INSPECTION 50 219/89 23) l , , P I I . I ' - I , e I - I . .. - - - . - .- - _. - .
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.. _ _ _ ll ll l INTRODUCliON I ' ISSUE
I DC CONTROL POWER TO USS IB2 WAS MISALIGNED TO STATION BATTERY 'A' INSTEAD OF STATION BATTERY 'B'. TO WHAT EXTENT DID THIS CONDITION IMPAIR THE OPERABILITY AND RELIABILITY OF SAFETY RELATED EQUIPMENT 7 , ?I POTENTIAL VIOLATIONS
' ' 'IWO APPARENT VIOLATIONS WERE IDENTIFIED. THE FIRST' .l INVOLVED " INADEQUATE PROGRAMMATIC CONTROLS TO j , IDENTIFY AND VERIFY PROPER LINEUP OF SAFETY RELATED COMPONENTS". THE SECOND INVOLVED "THE FAILURE TO PROPERLY kDENTIFY AND PROMPTLY CORRECT A CONDITION ADVERSE TO QUALITY".
I PRESENTATION WILL SHOW THAT: -* . THE CONDITION HAD MINIMAL SAFETY SIGNIFICANCE.
SAFETY SYSTEMS WOULD HAVE BEEN ABLE TO PERFORM THEIR FUNCTIONS.
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COMPREHENSIVE CORRECTIVE ACTIONS TAKEN TO PRECLUDE L RECURRENCE.
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. _ . _._ ._ .... _. _ - _ _... _... _.. . _. _ _ _ .. _ _- _. - _. _ _ ._ _,s - n e . I ' OVERVIEW ' i 1969 PLANT CONSTRUCTION COMPLETED. TWO NON SEISMIC 125V DC , STATION BATTERIES 'A' AND 'B' IN SAME ROOM.
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1979 "C' BATTERY INSTALLED. DIVISION A LOADS TRANSFERRED TO 'C" BATTERY. NEW BATTERY IS SEISMIC CATEGORY I.
Ll , H 1980 'B' BATTERY RACK UPGRADED TO SEISMIC CATEGORY I.
g l 1986 FEEDER CABLE FROM DC B TO USS 1B2 REPLACED DURING 11R OUTAGE I TO COMPLY WITH APPENDIX R. DC POWER SELECTED TO BATTERY "A" i , DURING MODIFICATION (10/15/86).
I 1989 ' DEVIATION REPORT 89-481 WRITTEN ON 9/16/89 DOCUMENTING DC ,. , i: CONTROL POWER FOR USS IB2 INCORRECTLY SELECTED TO BATTERY'A'. -
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L-10/15/86-APPENDIX R MODIFICATION TO REPLACE 125V DC B FEEDER CABLE TO USS 182. SELECTOR SWITCH PLACED TO BATTERY 'A' PER PROCEDURE 108. THREE TAGS HUNG (861562).
10/17/86 NEW 125V DC B FEEDER CABLE INSTALLED. RED LIFTED LEAD TAG REMOVED.
10/19/_86 RESPONSIBILITY FOR REMAINING 'IWO (2) YELLOW TAGS TRANSFERRED TO SU/T DEPARTMENT 'lV PERMIT TESTING.
I 11/02/86 TEST OF NEWLY INSTALLED CABLE COMPLETED (STP 436/13).125V DC FEEDER BREAKER (#13 ON DC CENTER "B") LEFT CLOSED BUT MANUAL SELECTOR SWITCH ON USS 1B2 REPOSITIONED TO BATTERY "A". AS LEFF SWITCH POSITIONS DOCUMENTED IN TEST PROCEDURE.
11/20/86 COMPLETE LINEUP OF 125V DC DISTRIBUTION SYSTEMS A & B PERFORMED PER PROCEDURE 340.1. (MANUAL SELECTOR SWITCH WAS NOT LISTED ON CHECK LIST PROVIDED IN PROCEDURE.)
11/29/86 TURNOVER OF SEVERAL APPENDIX R MODIFICATIONS CLOSED OUT.
PACKAGE INCLUDES DOCUMENTATION OF AS-LEFT POSITION OF USS - IB2125V DC SELECTOR SWITCH TO BATTERY "A".
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. .- .. - ... -. .. . -. .-- -. .- . -. .. - -. ll l.' , ' sl g OPPORTUNITIES FOR CORRECTION I 11/29/89 SWITCH SELECf10N 'ID "A" NOTED IN TURNOVER PACKAGE.
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- 2/25/89 9/15/89 . DURING THIS TIME PERIOD THIS SWITCH SELECTION TO THE 'A' . BATTERY WAS IDENTIFIED 'ID LICENSED OPERATORS AND AN , . OPERATIONS DEPARTMENT MIDDLE MANAGER.
L .i 9/16/89 UPPER MANAGEMENT INFORMED OF SWITCH POSITION.
SWITCH POSITION VERIFIED.
-:. .- SWITCH PROPERLY RE-POSITIONED.
< ~ NRC NOTIFIED.
' INVESTIGATION INITIATED.
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. ..- -- ... _. . . . -. - .-.e_ .._ - .-. .-. .
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2 ROOT CAUSE OF SWITCH MISPOSITIONING I ' ' PROCEDURAL INADEQUACY j I
PRIMARY INADEQUACY IN THAT THE MANUAL THROWOVER SWITCH'S f '
POSITION WAS NOT INCLUDED IN LINEUP CHECK LIST.
SECONDARY INADEQUACY IN THAT AS LEFT POSITIONS ARENT
, REQUIRED BY PROCEDURE 108 WHEN A TEMFORARY LIFT IS NOT TO , BE REHUNG.
' l ROOT CAUSE OF FAILURE TO PROMPTLY CORRECT LI PRIMARY
- ..
-
FAILURE OF INFORMED INDIVIDUALS 'IU UTILIZE PROPER ' CORRECTIVE ACTION PROGRAMS.
. l CONTRIBUTING THE TECHNICAL SPECIFICATIONS ASSOCIATED WITH THE ' BATTERY'B' ALIGNMENTWERE AMBIGUOUS.
[ ll ) I: I ,I I I: ,, - - - - , - -. !
., .._ _ _ __ .. _ _. _.. _ ... _ . _.. _ _ _. _. _. _ j . IMMEDIATE CORRECTIVE ACTIONS I P - '- ' INITIATED DEVIATION REPORT #89-481.
- REPOSITIONED SELEC1'OR SWITCH TO BA1TERY "B".
- MADE A 10 CFR 50.72 FOUR HOUR' NOTIFICATION.
- REVIEWED PROCEDURES AND DRAWINGS TO IDENTIFY SIMILAR SWITCHES.
- PERFORMED VISUAL VERIFICATION OF CORRECT POSITIONS.
] . I VISUALLY VERIFIED OTHER DC AND AC TRANSFER SWITCHES FOR
' CORRECT POSITIONS.
LI s IMPLEMENTED PROCEDURAL CHANGES TO LIST AND IDENTIFY REQUIRED
o POSITION OF DC SELECTOR SWITCHES.
I ' BRIEFED EACH ONCOMING SHIIT OF DIFFERENCES BETWEEN "A" AND "B"
BATTERIES AND REQUIREMENT TO SELECT SAFETY RELATED BA'ITERIES.
-l ' INDEPENDENT REVIEW GROUP WAS ESTABLISHED TO REVIEW EVENT AND ACTIONS TAKEN PRIOR TO PLANT STARTUP.
I i CONVENED AN INTERNAL INDEPENDENT REVIEW GROUP TO DETERMINE
ROOT CAUSE AND RECOMMEND ACTIONS TO PREVENT RECURRENCE.
I . ABOVE ACTIONS DISCUSSED WITH NRC REGIONAL MANAGEMENT IN A CONFERENCE . CALL ON 9/16/89 PRIOR TO PLANT STARTUP.
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, _ _ _ __ _. _._ _ __ _ _ _ _ _ . _. ~ _ _ _. _ _. _ _ _ _ _. ,[ E.' : o , ADDITIONAL CORRECTIVE ACTIONS l INTERNAL SECURITY DEPARTMENT INVESTIGATION INITIATED ON
. 9/18/89.
. EXTERNAL INDEPENDENT INVESTIGATION INITIATED ON 9/21/89 TO
' DETERMINE WHO KNEW OF SWITCH POSITION, WHEN THEY KNEW OF - IT, AND IF SUCH INFORMATION WAS PROPERLY ADDRESSED
(SUPERSEDED INTERNAL SECURITY DEPARTMENT INVESTIGATION)- l .. SITE DIRECTOR MEMO EMPHASIZING REQUIREMENT TO DOCUMENT
- DEFICIENT CONDITIONS ISSUED 9/22/89. PRESIDENT GPUN ISSUED L SIMILAR COMPANY WIDE GUIDANCE.
PROCEDURE 108 HAS BEEN REVISED TO IMPLEMENT COMPUTERIZED
TAGGING SYSTEM. THIS SYSTEM GENERATES COMPONENT POSITION h l- ' REQUIREMENTS WHENEVER A TAGOUT REMOVAL WORK SHEET IS GENERATED.
~
PROCEDURE 108 HAS BEEN REVISED TO ENSURE TAGGED COMPONENTS
- LISTED IN APPLICABLE SYSTEM LINE-UP SHEET.
I A PROGRAM IS IN PLACE TO REVIEW COMPONENT LINEUPS,
OPERATING PROCEDURES, AND DRAWINGS TO ENSURE THAT ALL . COMPONENTS ARE LISTED ON LINE UP SHEETS. THIS DATA IS - BEING CAPTURED ON A COMPUTERIZED DATA BASE. THIS DATA WILL BE USED TO GENERATE ACCURATE, THOROUGH AND STANDARD SYSTEM LINEUP SHEETS.
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- .-. . ..- - . .. - ..-._----- - - -.- . > i ,.
- w
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- p ADDITIONAL CORRECTIVE ACTIONS l
,, " w < SURVEILLANCE PROCEDURE BEING DEVELOPED TO PERIODICALLY
CONFIRM PROPER POSITIONS OF CRITICAL ELECTRICAL COMPONENTS.
' (PROCEDURE M PERIODICALLY PERFORM ONE OF THE IMMEDIATE . CORRECTIVE ACTIONS.)
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TRAINING PROGRAMS WILL BE ENHANCED 'IO INTRODUCE TRAINEES TO ' THE IDENTIFICATION AND UTILIZATION OF CORRECTIVE ACTION
PROGRAMS.
, t ' PROCEDURE REVISED TO REQUIRE ALL COMPONENTS LISTED ON
TURNOVER NOTIFICATIONS 'IV BE VERIFIED FOR PROPER POSITION.
THE SYSTEM LINEUP CHECK LIST MUST BE CHECKED TO ENSURE ALL-l TURNOVER LISTED COMPONENTS ARE LISTED AND POSITIONS - i SPECIFIED.
j . I
TRAINING MATERIALS WILL BE REVISED TO INCORPORATE THIS INCIDENT AS A LESSONS LEARNED ITEM.
' , . SWITCH MODIFICATIONS WILL BE MADE TO PREVENT RECURRENCE.
' .I Q TECHNICAL SPECIFICATION CHANGE TO ELIMINATE AMBIGUITY
ASSOCIATED WITH THE REQUIREMENT TO SELECT BATTERY "B" HAS BEEN SUBMITTED TO THE NRC.
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,i:}i, l - s y * J,.. . e; - I smo nw=rERY ?^mna ene n'rTERY LOGS I B ENERGENCY BEARING OIL PUMP CONTINUOUS INSTRUNENT SUS #3 ROTARY INVERTER DC MOTOR 'NCC DC-1 - ALTERNATE SOURCE MCC DC-1 - NORMAL SOURCE POWER PANEL DC-D - ALTERNATE SOURCE POWER PANIL DC-D - NORMAL SOURCE E, c 4160 VAC SWITCEGRAR'1B CONTROL POWER 4160 VAC SWITCEGEAR 18 CONTROL POWER - ALTERNATE SOURCE - NORMAL SOURCE B 4160 VAC SWITCEGRAR 1D 00NTROL' POWER .4160 VAC SWITCEGEAR 1D CONTROL POWER ALTERNATE SOURCE - NOEMAL SOURCE =480 VAC UNIT SUBSTATIOlt 182 CONTROL 490 VAC UNIT SUBSTATION 182 CONTROL 'PCWER -. ALTERNATE SOURCE PONER - NORMAL SOURCE , 480 VAC UNIT SUBSTATION 151 AND 133 480 VAC UNIT SUBSTATIONS 153 CONTROL POWER - ALTERNATE SOURCE CONTROL POWER - NORMAL SOURCE-HICITATION SWITCEGRAR CONTROL POWER POWER PANEL DC-E - ALTERNATE SOURCE B POWER PANEL DC-3 NORMAL SOURCE DIESEL GENERATOR 2 ENERGENCY SWITCEGEAR CONTROL POWER - ALTERNATE SOURCE ENER0ENCY SEAL OIL PUMP l 480 VAC UNIT SUBSTATION 1B1 CONTROL POWER - NORMAL SOURCE .. B .
- 'i a; i .' SAFETY ASSESSMENT DESIGN COMPARISON OF MAIN STATION BATTERIES . PARAMETER STATION SATTERY t, STATION SATTERY S ' STATION SATTERY A ' PMSICAL ARRANGEMNT TURSINE BLDG OFFICE etDG. 2 2 F100R, SeqE As 'B' 94TTERT EL. 23'-6" EL. 35'-0" SEPI. RATION COMPLETELY PNYSICALLY PNYSICALLY AN" ELECTRICALLY NON-CLASS 1E, PWYSICALLY & & ELECTRICALLY SEPARATED SEPARATED FROM 'C' SATTERY SYSTEM ELECTRICALLY SEPARATED F9tN6 'C' SATTERY FROM A & B STATION SATTERIES 'S' & 'A' ARE IN THE SA E GENERAL AREA S & C ARE REDUNDANT CLASS IE SYSTfB 'B' CELLS SEPARATED FROM 'A' CELLS SY A 'C' SATTERY SYSTEM CABLES IN-ROLLER 000R. ROLLER 000R PREVENTS SOME STALLED IN ColNIUITS; C(frLETELY ColNION MtBE FAILURE ECNANISBIS.
SEPARATED FROM REST OF PLANT CABLES BATTERY SIZE & TYPE GNO, LEAD CALCitet,1200 AMP GNO LEAD ANTIMONY 1200 AfN' NRS.
SAME AS 'O' 9ATTERY NOURS, BASED ON 8 INI. DIS-SASED ON 8 NR. DISCHARGE, 60 CELLS CHARGE, 60 CELL CAPACITY MARGIN 185%, 20 YEARS LIFE 35.8%, 20 YEARS LIFE ZERO PERCENT (DUE TO LARGE MDTOR LOADS).
DESIGN LIFE 20 YEAR CAPACITY CALCULATION BASED ON ALL 'B' BATTERY LORDS TRANSFERAGLE TO 'A' BATTERY SEISMIC SYSTEM INSTALLED IN 1979.
ORIGINAL EQUIPMENT. SATTERY S RACK ORIGINAL EQUIPE NT. PURCHASED / INSTALLED SATTERIES/ RACKS & ALL ASSOC.
- WLS 840DIFIED & UPGRADED TO SEISMIC. TO THE SA E ORIGINAL SPEC. AS 'O' OATTERY EQUIPMENT IS SEISMICALLY CAT. 1 SY A 1980 pe0DIFICATION SYSTEM QUAttflED TO MEET IEEE 344 UNDER 9/A 402034, ALL 'O' BATTERY DIST. SYSTEM PANELS /MCCs W RE REVIEWED AND FOUND TO BE EITNER SEISMICALLY CUALIFIED OR WERE UPGRADED TO SEISMICALLY QUALIFIED.
, TESTING SAME SAME SAME
, -._ _ _.
_ . . _ _. .. _ _ _.
. _ - _ _ _ _ _ _. _.. ._..c.
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- '
,. - . SAFETY ASSESSMENT , TESTING COMPARISON OF. MAIN STATION BATTERIES BATTERY INSPECTION / TESTS BATTERY ' WEEKLY: A B C . . '1.
CHECK BATTERY CHARGER VOLTAGE X X X J2.
CHECK VOLTAGE'OF PILOT CELL X X X 3.
CHECK CHARGER CURRENT X X X , 4.
CHECK SPECIFIC GRAVITY OF PILOT CELL X X X 5.- CHECK WATER LEVEL OF ALL CELLS X X X 6.
VISUAL INSPECTION OF ALL CELLS FOR ANY ABNORMALITY X X X i - 7.
CHECK CELL TERMINAL CONNECTIONS ARE CLEAN AND FREE ' . OF CORRUSION X X X ' b MONTHLY:- 1.
CHECK BATTERY CHARGER VOLTAGE X X X . 2.
CHECK VOLTAGE OF PILOT CELL X X X I 3.- CHECK CHARGER CURRENT X X X I 4.
. CHECK SPECIFIC GRAVITY OF PILOT CELL X X X 5.
CHECK WATER LEVEL OF ALL CELLS X X X 6.
VISUAL INSPECTION OF ALL-CELLS FOR ANY ABNORMALITY X X X EVERY REFUELING OUTAGE: .. 1.
CHECK BATTERY VOLTAGE X .X X 2.. CHECK VOLTAGE OF PILOT CELL X X X " * " ' " " ' " ^ " " " " " " "
I 4.. CHECK SPECIFIC GRAVITY OF ALL CELLS AFTER RECHARGE X X X- - 5.
CHECK WATER LEVEL OF.ALL CELLS X X X . {3 - 6.
VISUAL INSPECTION OF ALL CELLS FOR ANY ABNORMALITY X X X 2.
CHECK 1NTER-CEtt RESISTANCE x x x .. 8.- BATTERY CAPACITY TEST X X X l .AHR/bl
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g . Group Heading , . 4601 STATION POWER U-4-d
CNTRL DC L 1B2 s l DC LOST . . ... ,
. CAUSES: SETPOINTS: ACTUATING DEVICES: . Loss of 125 V.D.C.-control power to the Loss of 80 Relay ' -control circuits for the unit substations 125 V.D.C.
H .on 460 volt bus 182.
Electrical tripping control power and closing functions for affected units are defeated.
. Reference Drawings: Gell 688328 Sh. 17 , , GU 30-732-17-1002,.Sh 17 - . , , CONFIRMATORY ACTIONS: Check 125 V.D.C. battery voltage and battery charger-status at 8F/9F.
. ~ AUTOMATIC ACTIONS: . NONEz o-MANUAL CORRECTIVE ACTIONS: Refer to Procedure ABN-3200.13, " Loss of 125 VDC Control Power".
Restore normal 12S V.D.C. control power supply or tran'sfer to alternate supply at unit sub 182M-as necessary. Return system to norrr.&1 when possible.
t ' Subject-Procedure No.
Page 1 of 1 ELECIRICAL 2000-RAP-3024.02 U-4-d . .
Alarm Response , i ' Procedures Revision No:
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__ _ _ _ _._ _ _. _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ .; I ' SAFETYASSESSMENT 8, CONCLUSIONS , p
- ONLY SIGNIFICANT DIFFERENCE IS 'B' AND 'C' STATION BATTERIES ARE SEISMIC L
CATEGORY I,'A' BATTERY IS NOT.
l
- ONLY USS IB2 BREAKER CONTROL FUNCTIONS AT RISK UNDER A SEISMIC EVENT (ALL OTHER SAFETY RELATED LOADS POWERED FROM 'B' BATTERY WERE PROPERLY ALIGNED)
, lI
- LOSS OF 125V DC CONTROL POWER TO USS IB2 IS ALARMED.
- SAFETY RELATED LOADS POWERED THROUGH USS 182 ARE REDUNDANT TO SAFETY
, RELATED LOADS POWERED BY USS 1A2.
I USS 1B2 LOADS USS 1A2 LOADS
l l FEEDER TO MCC 1B24 TIE TO USS 1B2 - - CONTAINMENT SPRAY PUMP 1-4 CONTAINMENT SPRAY PUMP 11 - i - SHUTDOWN COOLING PUMP NUO2C SHUTDOWN COOLING PUMP NUO2A - - REACTOR BUILDING CLOSED COOLING-REACTOR BUILDING CLOSED COOLING i WATER PUMP 12 WATER PUMP 11 ' - CONTAINMENT SPRAY PUMP 13 CONTAINMENT SPRAY PUMP 12 - - FEEDER TO MCC 1B23 FEEDER TO MCC 1A24 - - CRD FEED PUMP NC08B CRD FEED PUMP NC08A ' - - FEEDER TO VMCC IB2 FEEDER TO VMCC 1A2 - - FEEDER TO MCC IB21 FEEDER TO MCC 1A21 - f - FEEDER TO MCC 1B22 FEEDER TO MCC 1A22 - ' - POWER DISTRIBUTION PANEL B2 POWER DISTRIBUTION PANEL A2 - - BUILDING EXHAUST FAN EF 1-6 BUILDING EXHAUST FAN EF 15 - . SHUTDOWN COOLING PUMP NUO2B FEEDER TO MCC 1A23 - ig - CORE SPRAY BOOSTER PUMP NZ03B CORE SPRAY BOOSTER PUMP NZ03A -
- CORE SPRAY BOOSTER PUMP NZO3C CORE SPRAY BOOSTER PUMP NZO3D - I
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SAFE SHUTDOWN I
JPSAR SECTION 430. TOPIC VII 1 SYSTEMS REQUIRED FOE SAFE SHUTDOWN '
10CFR50 (GDC 2 & 34), AS IMPLEMENTED THROUGH SRP SECTIONS 5.4.7, BTP RSB 51, AND REGULATORY GUIDE 1.129, IN PART, REQUIRES 'IIIAT THE SEISMIC - CATEGORY I WATER SUPPLY FOR DECAY HEAT REMOVAL HAVE SUFFICIENT INVENTORY TO PERMIT OPERATION AT HOT SHUTDOWN COOLING SYSTEM (SCS) INITIATION.
] THE INVEN'IDRY IS BASED ON THE COOLDOWN TIME ASSUMING A SINGLE ACTIVE FAILURE AND EITHER ONLY ONSITE OR ONLY OFFSITE POWER.
. ' SAFE SHUTDOWN SYSTEMS: ' L CORE SPRAY (MAIN PUMPS) ! ' - ADS ' - - CONTAINMENT SPRAY /ESW - ,.
I
- IF DG #1 IS ASSUMED AS THE ACTIVE FAILURE (DG-1 FEEDS USS 1A2 LOADS)
' AND USS IB2 IS INOPERABLE DUE TO A LOSS OF DC CONTROL POWER, A LOSS OF CONTAINMENT SPRAY PUMPS RESULTS.
CONTAINMENT SPRAY IS REQUIRED FOR LONG TERM CONTAINMENT DECAY HEAT REMOVAL AND WOULD BE REQUIRED TO BE RESTORED WITHIN 90 MINUTES TO PRESERVE CORE SPRAY PUMP NPSH LIMITS.
- IT IS REASONABLE TO EXPECT THAT OPERATORS WOULD RECOGNIZE AND CORRECT I
LOSS OF DC WITHIN 90 MINUTE INTERVAL SINCE LOSS OF DC CONTROL TO USS IS ALARMED; THUS RESTORING CONTAINMENT SPRAY SYSTEM II TO OPERABLE . ' STATUS.
-
- IT IS ALSO IMPORTANT TO NOTE THAT ALTHOUGH IC IS NOT CONSIDERED AS PART OF SAFE SHUTDOWN SYSTEMS BECAUSE OF NON SEISMIC MAKEUP, THEY WOULD PROVIDE 45 MINUTES PER CONDENSER OF DECAY HEAT REJECTION BASED I
UPON STORED WATER INVENTORY IN IC SHELL. THIS TIME IS ADDITIVE TO THE 90 MINUTES REQUIRED TO RESTORE CONTAINMENT SPRAY.
- SAFETY SIGNIFICANCE OF MISPOSITIONED SWITCH IS MINIMAL IN THAT
- OPERATOR ACTION TO PROPERLY REPOSITION THE SWITCH CAN EASILY BE TAKEN BEFORE LOSS OF SAFE SHUTDOWN CAPABILITY RESULTS.
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] . SEVERITY LEVEL CONSIDERATIONS . E
EVENT DID NOT INVOLVE A VIOLATION OF A SAFEW LIMIT
- I
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SAFETY SYSTEMS WERE NOT CALLED UPON TO ACTUATE
, I NO RELEASE OF RADIOACTIVE MATERIAL OCCURRED
Hg TECHNICAL SPECIFICATIONS WERE NOT VIOLATED; HOWEVER, '- l, 5 i: , h SPECIFICATION IS AMBIGUOUS AND CHANGE SUBMITTED qg LOSS OF CONTROL POWER ALARMS IN CONTROL ROOM -
OPERATOR ACrION WILL RESTORE FUNCTION S FEw FUNCrIONS WERE NOT oEcRioso.
- , PROMM AND THOROUGH INVESTIGATION AND CORRECTIVE
)I ACTIONS i f NO WILLFULWRONGDOING OR CARELESS DISREGARD FOR
L REQUIREMENTS
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. . 3,. . . INTRODUCTION ISSUE COULD ESW/CS SYSTEM HAVE EFFECTIVELY PERFORMED WITHIN THE DESIGN BASIS WHEN OPERATED WITH THE ESW SYSTEM DISCHARGE VALVES IN THE PRESENT THRO'ITLED POSITION AND WITH ELEVATED CANALTEMPERATURES7 I EOTENTIAL VIOLATION "THE LICENSEE'S USE OF NON CONSERVATIVE CALCULATION ASSUMITIONS, FAILURE TO EFFECTIVELY EVALUATE OPERATION OF THE ESW/CS SYSTEMS WITH THE ESW DISCHARGE VALVES THRO'ITLED AND THE I FAILURE TO RECOGNIZE THESE DEFICIENCIES GIVEN THE IDENTIFICATION OF SIMILAR, RELATED PROBLEMS IS A POTENTIAL VIOLATION."- I ENFORCEMENT ACTION I NRC IS CONSIDERING ENFORCEMENT ACTION WITH REG ARD TO THE LACK - ._ OF TIMELY FOLLOW UP TO IDENTIFIED ITEMS AND THE POSSIBILITY THAT THE PLANT WAS OPERATED IN AN UNANALYZED CONDITION.
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SSFI INSPECTION REPORT REFERENCES THNi' ESW DISCHARGE VALVE
THROTTLED ISSUE IS RELATED TO VIOLATION A OF INSPECTION REPORT 89 16 (85' INTAKE CANAL TEMPERATURE).
L " BY LETTER DATED 9/17/89, GPUN RESPONDED TO VIOLATION A OF { ' INSPECrlON REPORT 8946.
E GPUN AGREES THATTIMELY AND APPROPRIATE FOLLOW UP
, , REGARDING THE DOCUMENTATION OF THE EVALUATION CONDUCTED IN , , i 1988 DID NOT OCCUR.
- VE ' THE ISSUES ARE RELATED IN THAT ELEVATED CANAL TEMPERATURE 'i ' IS A COMMON PARAMETER.
ISSUES ARE NOT RELATED WITH REGARD TO TIMELY FOLLOW UP.
- t:
- PRESENTATION WILL SHOW THAT: .. ESW/CS SYSTEM WOULD HAVE EFFECTIVELY PERFORMED WITHIN THE -
DESIGN BASIS WHEN OPERATED WITH THE ESW SYSTEM DISCHARGE VALVES IN THE THROTTLED POSITION AND ASSUMING ELEVATED CANAL TEMPERATURES.
E . . ' GPUN DID USE CONSERVATIVE CALCULATIONAL ASSUMPflONS ' . GPUN DID NOT FAIL TO EFFECTIVELY EVALUATE OPERATION OF THE
. ESW/CS SYSTEMS WITH ESW DISCHARGE VALVES THROTTLED AND .WITH ELEVATED CANAL TEMPERATURES.
THIS IS NOT AN EXAMPLE OF A LACK OF TIMELY FOLLOW UP TO AN
IDENTIFIED ITEM.
I --. - - . . ..
.;* : .l) - - .a... - ' t , I CONTAINMENT SPRAY /ESW I GENERAL DESIGN FUNCTION REMOVE HEAT FROM PRIMARY CONTAINMENT AND IN - ' CONJUNCTION WITH CORE SPRAY, ASSURE CONTINUITY OF COOLINGi-E ' * .-THE PARAMETER OF INTEREST IS HEAT REMOVAL - CAPACITY.
, I SYSTEM DESIGN OBJECTIVE I REMOVE POST ACCIDENT ENERGY SUCH THAT TURN AROUND
- OF DRYWELL AND TORUS PRESSURE AND TEMPERATURE CAN - BE ACCOMPLISHED. THE PEAK VALUE OF THESE . PARAMETERS IS REQUIRED TO BE CONSISTENT WITH EQUIPMENT PERFORMANCE AND CONTAINMENT DESIGN I REQUIREMENTS, 'I EXAMPLE OF EQUIPMENT PERFORMANCE CONSIDERATIONS I TORUS TEMPERATURE AS IT AFFECTS NPSH FOR CORE
SPRAY AND CONTAINMENT SPRAY I I - -
-,. ~. _ _. -_ ._ ~__ . - -. _. _.. _.. _ _ _ _. _ _ _. - _. _. -.. _ _ - _. _ - _... _ , , , .4' I ' .. ~ CONTAINMENT RESPONSE ANALYSIS SUMMARY
- g; STARTING IN 1980 GPUN HAS CONDUCTED NUMEROUS
CONTAINMENT RESPONSE ANALYSES UTILIZING CONTEMPT.
i E THERE HAS BEEN CONTINUITY OF ENGINEERS INVOLVED
RESULTING IN A STRONG UNDERSTANDING OF SYSTEM RESPONSE AND SENSITIVITIES.
I > i MAY 1986 ANALYSIS CONFIRMED ACCEPTABILITY OF 2370 GPM
ESW TO THE HEAT EXCHANGER. THIS WAS THE CULUMINATION
OF NUMEROUS SENSITIVITY STUDIES CONDUCTED AFTER MAY 1980.
' . SENSITIVITY STUDIES CONDUCTED 1980 THRU 1986 VARIED INPUT PARAMETERS SUCH AS CS/ESW FLOW / CANAL TEMPERATURE / INITIAL TORUS TEMPERATURE.
l THESE STUDIES LEAD TO AN UNDERSTANDING OF THE -
' SENSITIVITY TO CANAL TEMPERATURE, FOR EXAMPLE, THE ENGINEERS KNOW THAT A l'F INCREASE IN CANAL TEMPERATURE ABOVE 85'F WOULD RESULT IN LESS THAN l'F INCREASE IN PEAK TORUS TEMPERATURE.
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~eMwJ- --- 4~4.4---d 4d w4hA-A mem e-J.-a- s%mu-.MWJ# we-A 4s-m-d.- h.- sur ,. -,, -. I CHRONOLOGY CS/ESW PERFORMANCE (FLOW / HEAT REMOVAL ISSUES) 5/16/80: TDR 165, PERFORMANCE EVALUATION OF OCNGS I CONTAINMENT SPRAY HEAT EXCHANGERS. INVESTIGATED DBA LOCA CONTAINMENT RESPONSE FOR A VARIETY OF HEAT REMOVAL RATES. COMPARED WITH GE DOCKETED ANALYSES 'IV BENCHMARK CONTEMIT. IDENTIFIED TORUS TEMPERATURE AS A FACTOR RELATING TO ADEQUATE NPSH > FOR CORE SPRAY PUMPS.
10/7/83: CALC. #C 1302 2415360-004 EVALUATED THE CS/ESW , SYSTEM PERFORMANCE AT A MINIMUM ESW FLOW OF 2370 L GPM TO HL RESULT REPORTED THAT HEAT REMOVAL RATES OUTLINED IN TDR 165 ARE MET.
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- PSC 84-002 ON RUITURE OF NON. SEISMIC PIPING CONNECTED TO ESW SYSTEM.- RUPTURE WOULD POTENTIALLY DIVERT FLOW FROM HL E 2/8/85: PSC 85 004 ISSUED CONCERNING CORE SPRAY PUMP - RUNOUT FLOW AND NPSH AVAILABLE, PSC IDENTIFIED > POTENTIAL NPSH INADEQUACY WHEN CORE SPRAY PUMPS OPERATE AT RUNOUT (APPROX. 5000 GPM) WITH ELEVATED i TORUS TEMPERATURES (>150*F) AND NO TORUS OVERPRESSURE.
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- I CORE SPRAY NPSH REQUIRED - @ 4100 GPM (REQ'D APP. K FLOW): 16.5 R. = peak torus temp < 177 @ 5000 GPM (RUNOUT FLOW): 20 R. = peak torus temp. < 150 ' I 10/4/85: CALC, #C 1302-532 5360 007 PERFORMED IN SUPPORT OF -- I RESPONSE TO PSC 84-002; RESULTED IN AN INCREASED ' PUMP OPERABILITY LIMIT OF 2800 GPM IN ORDER TO l ENSURE A MINIMUM OF 2370 GPM TO THE HXs.
'I' i 12/12/85: TDR 701 EVALUATION TO ASSESS THE OVERALL ADEQUACY OF ESW SYSTEM. RECOMMEND THE FOLLOWING: INSTALL c - ANNUBAR IN ESW SYSTEM II, TEST ESW PUMPS AT ' VARYING FLOWRATES TO DEVELOP SYSTEM HEAD CURVE; ' THRO'ITLE ESW PUMPS TO A FLOW POINT BELOW RUNOUT IN ORDER TO REGAIN PUMP HEAD AND INCREASE TUBE SHELL DP.
4/22/86: CALC. #1302 212 5360-023 ISSUED IN RESPONSE TO PSC 85-004 CORE SPRAY SYSTEM FLOW. RESULTS INDICATE , ADEQUATE NPSH IS AVAILABLE UNDER THE CONDITION OF NO OVERPRESSURE FOR ALL CORE SPRAY PUMPS AT c ASSUMED RUNOUT FLOW OF 5000 GPM.
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$ .f ^ , .1 : 5/2/86: TDR 716 ISSUED IN RESPONSE TO PSC 85 004 TO / PROVIDE A BEST ESTIMATE OF CONTAINMENT RESPONSE , TO DBA LOCA BY ELIMINATING CONSERVATISMS' PREVIOUSLY USED IN CONTEMPT ANALYSIS. UTILIZED CORE SPRAY RUNOUT FLOW OF 5000 GPM. TDR " ASSESSED EFFECTS OF 2370 GPM ESW FLOW TO THE
HX.
9/17/ 86: SYSTEM FUNCTIONAL AUDIT REPORT S-OC-86-05 ISSUED RESULTING IN PSC 86-016 THAT CS/ESW ' ~ SYSTEMS WERE ANALYZED AT CS FLOW OF 4300 GPM IN ' THE TORUS COOLING MODE VS. APPROXIMATELY 4000 '. ,' . GPM NORMALLY RECORDED DURING TESTING.
s b ' 11/25/86:- IOM #5450-86-0198 RE-EVALUATED CONTAINMEMT [ RESPONSE TO DBA LOCA UNDER CS FLOW CONDITIONS , OF 4000 GPM TORUS COOLING FLOW AND 3625 GPM D/W SPRAY FLOW WITH ESW AT 2370 GPM DELIVERED TO ' HEATEXCHANGERS. RESULT: MINIMAL (<1'F) INCREASE IN PEAK TORUS TEMPERATURE OVER THAT I REPORTED IN TDR 716 DUE TO REDUCTION IN CS FLOW FROM 4300 GPM TO 4000 GPM IN TORUS COOLING MODE.
< < l CONCLUSIONS: CHRONOLOGY SHOWS THAT ANALYSES PERFORMED 1980 - 1986 DEMONSTRATED ADEQUATE HEAT TRANSFER WITH CONSERVATIVE INPUT ASSUMPTIONS.
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-1 E CHRONOLOGY CS/ESW TUBE TO SHELL DP t 9/15/78: I&E INSPECTION 7819 IDENTIFIES UNRESOLVED ITEM j CONCERNING NEGATIVE TUBE TO SHELL PRESSURE DIFFERENTIAL I 9/30/84: SE 00241-001 EVALUATING THE REVERSE DP CONDITION.
l BASED UPON ANALYSIS UTILIZING MIDAS NO SIGNIFICANT L INCREASE IN OFFSITE DOSE.
12/12/85: TDR 701 EVALUATION TO ASSESS THE OVERALL ADEQUACY t l ' L OF ESW SYSTEM. RECOMMEND THE FOLLOWING: INSTALL
ANNUBAR IN ESW SYSTEM II, TEST ESW PUMPS AT . ' VARYING FLOWRATES TO DEVELOP SYSTEM HEAD CURVE; THRO 1TLE ESW PUMPS TO A FLOW POINT BELOW RUNOUT IN ORDER TO REGAIN PUMP HEAD AND INCREASE TUBE-SHELL DP.
i u, 5/2/86 TDR 716 AND SUBSEQUENT REVISIONS DOCUMENT THE ACCEPTABILITY OF 2370 GPM ESW FLOW TO HX.
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, _.. _. _. _. _ _. _.. _ _.. _ _ _ _ _ _. _. _ _ _ _ _ _ _ _ _ _. _ __ i I ,. ? - .; a , 9/15 86: . IOM MSS 86 354 RECOMMENDED THROTTLING HX OUTLET / I VALVE BASED UPON RESULTS OF PUMP OPERABILITY TESTING AND TDR 716 IN ORDER M RE-ESTABLISH - POSITIVE DP.
' ' I 10/86 HX OUTLET VALVES THROTTLED UPON STARTUP FROM , 11R. ESW FLOWM HX ASSURED AT >2370 GPM BY- ' ' . SURVEILLANCE TESTS. ACCEPTANCE CRITERIA FOR OPERABILITY WAS ESW FLOW >2800 GPM.
{ E i CONCLUSION: CS SYSTEM OPERATION WITH ESW OUTLET VALVES
' THROTTLED WAS ANALYZED PRIOR TO STARTUP FROM 11R OUTAGE.
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CHRONOLOGY , ESW INTAKE TEMPERATURE ISSUE
J I BACKGROUND: AS PART OF THE SYSTEM' DESCRIITION, THE FSAR GIVES THE HEAT DUTY OF THE CS HXs AS 50 MBTU/HR AT AN INTAKE TEMPERATURE OF 85'F. INTAKE TEMPERATURE IS RECORDED HOURLY IN THE CONTROL ROOM BUT IS NOT A DESIGN BASIS LIMIT OR A LIMIT I FOR PLANT OPERATION.
' 7/88: INTAKE TEMPERATURE EXCEEDED 85F' (87'F); h CONTEMPT ANALYSES PERFORMED AT 90*F INDICATES NO SIGNIFICANT EFFECT ON CONTAINMNET RESPONSE TO DBA LOCA. TORUS PEAK TEMPERATURE INCREASES TO APPROXIMATELY 152*F. THIS WAS NOT l CONSIDERED A SIGNIFICANT IMPACT ON SAFETY FUNCTION OF CORE SPRAY SYSTEM. PROVIDED RESPONSE TO PLANT VERBALLY.
I 7/28/89: INTAKE TEMPERATURE EXCEEDS 85'F AGAIN (86*F).
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ADDITIONAL CONTEMPT ANALYSES AT 75% REACTOR
[ POWER (LOAD LIMITED DUE TO TRANSFORMER OUTAGE) ) AND 95'F INTAKE TEMPERATURE. RESULTS SHOWED TORUS PEAK TEMPERATURE OF APPROXIMATELY 142*F.
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,,, , _ _ - - -, - - - -, - -, - - - - - - - -, - - - - - - - - - -, - - f E 7/28/89 SINCE THE CS/ESW SYSTEM FLOWS BEING MEASURED I (Cont'd) DURING OPERABILIW TESTS WERE GREATER THAN THOSE ASSUMED IN THE ANALYSES UP M 'IIIIS POINT, GPUN DECIDED M INCREASE CS/ESW OPERABILITY LIMITS AND RUN 'IME ANALYSIS WIM THE HIGHER FLOWS.
k 10/27/89 CAirULATION #C 1302 2415480 u39 USING CONTEMPT EVALUATED CONTAINMENT RESPONSE TD A DBA.LOCA WITH I 3200 GPM D/W SPRAY FIAW AND 3300 GPM TOTAL ESW
FLOW (3000 GPM TO HX). CONFIRMED ACCEPTABILITY OF 90*F INTAKE TEMPERATURE AT 100% POWER. MRUS PEAK TEMPERATURE OF APPROXIMATELY 157'F.
' h CURRENT CS/ESW OPERABILITY TEST LIMITS: I CS 13800 GPM MTAL(TORUS COOLING MODE) =3200 GPM TOTAL (D/W SPRAY MODE) ESW 13300 GPM TOTAL =3000 GPM M HX CONCLUSION:THIS CONFIRMS THAT THE PLANT NEVER OPERATED OUTSIDE ANALYZED CONDITIONS.
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LI EMERGENCY SERVICE WATFE PUMP SURVEli I ANCE TESTING i AS PUMP LEFT
- JiI OPERABILITY CONDITION
, VALVE POSITION THROTTLED OPEN10 OPEN TO MECHANICAL MECHANICAL STOP STDP I FLOW (gpm) 3200 1 50 2,3300 OPERABILITY (CURRENT VALUE) FLOW PUMP DP (psid) 153 164 NOT APPLICABLE NOT APPL 1 CABLE I I
- INSERVICE TESTING DONE TO ASSURE COMPONENT HEALTH PER ASME XI.
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M I I SAFETY SIGNIFICANCE COMPARISON WIDI FSAR I FSAR DBA CONTAINMENT ANALYSIS IS BASED UPON MAXIMIZING PEAK
PRESSURE TO SHOW ADEQUACY OF11)RUS AND DRYWELL DESIGN PRESSURES I ANALYSIS TO MAXIMlZE PRESSURE WILL TEND TO REDUCE PEAK TORUS
TEMPERATURE I ' I EVALUATION BASED STRICTLY UPON EXISTING FSAR ASSUMPTIONS WOULD
' PROVIDE ADDITIONAL MARGIN TO NPSH LIMITS I I E I I I E I
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _- M M&M MS M & & & 'M MM M8 MW8 M ,. - SAFETY SIGNIFICAER - ; i-COMPARISON WITE FSAR A861mFTIONS .. ' . MODIFIED 18AR mASE 18AR COWrEMPT COWrEMPT ASSUNPTIONS CASE CONTEMPT BASE CASE CASE I DRYWELL PRESSURE l 15.0 P8IA l 15.9 PSIA
DRYW5LL TEMPERATURE l 135'F l 150*F ! DRYWELL HUMIDITY l 100% l 30% TORUS TEMPERATURE l 90*F l 95'F '
3 TORUS POOL TOLUME l 92,000 FT l 82,000 FT l
CCEX BTC l 400 BTU /ER-FT *F 321 l 231.9 321 E8W TEMPERATURE l 85'F l 90*F ! START DELAY IN C8/E8W l NOME 85 SBC l 85 8BC POWER LEVEL l 1860 MWt 1930 MWt l 1930 MWt i r DECAY REAT l GE CURVE l GE , CLOWDOWN l GE DATA l GE ET/NT NULTIPLIER l EQUILIBRIUM 3.9 l 140
j RETENTION OF NASS l IN DW FLOOR NO YMS i YE5 i
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MEAT SINES l NO TES j rzs ! '
f NODE j DW SPRAY l DW SPRAY . . l C3 FLOW l 6000 GEM 3200 l 3200 j i ECW FLOW l 6000 GPM 3000 l 3000
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. _ _ _. _ _. _ -... _, _. _. _ _ _ _.. _ _ _. ~. ~. _. _. _ _. _ _ _ _... , l..' 1 2 . REFETY SIGNIFIC&MCE COMP &RISOM WITE FB&R RESULTS l ' ' FEAR TORUS MININUM G&EE TEMPERATURE AYhILABLE NPSE FSAR BASE 142*F (FIGURE 6.2-5) UNKNOWN I (WTC a 400) i ' CS a 6000 ' BSW m 6000 E FSAR CONTEMPT 145.S'f At 28.5 FT , (NTC a 321)
27.9 I (PUNF OF LIMITS) C 25.7 D3 28.3 CONTEMPT BASE 157'F At 26.4 D: 25.76 C 23.57 I D 26.14 - , MODIFIED CONTEMPT 154.6 At 27.0 FT (NTC = 321) at 26.4 Ct 24.1 " D 26.7 ,
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I SAFETY SIGNIFICANCE ' PEAK DRYWELL TEMPERATURE AND PRESSURE UNAFFECTED BY CS/ESW
ASSUMirrIONS l
PEAK TORUS PRESSURE UNAFFECTED BY CS/ESW ASSUMI"rIONS SENSITIVITY OF PEAK TORUS ID TEMPERATURE TO CS/ESW ' I,
ASSUMPTIONS HAS BEEN WELL UNDERSTOOD FOR A NUMBER OF YEARS l ! CANAL TEMP +5'F = 2*F ON PEAK TORUS TEMP - ' TORUS VOLUME + 10,000 IY = +57 ON PEAK TORUS TEMP
INITIAL TORUS TEMP +10T = +6*F ON PEAK TORUS TEMP ETC.
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MARGIN BETWEEN TORUS TEMP LIMIT FOR 'C" CORE SPRAY PUMP [ ' I NPSH AND CONSERVATIVELY CALCULATED PEAK TORUS TEMP IS I APPROXIMATELY 20*F I . S
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CONCLUSIONS: PIANT WAS NOT OPERATED IN AN UNANALYZED CONDITION.
- ASSUMING THROTTLED ESW DISCHARGE VALVES AND ELEVATED CANAL
TEMPERATURES, THE ESW/CS WOULD HAVE EFFECTIVELY PERFORMED ITS IN1 ENDED FUNCTION WITHIN 1HE DESIGN BASIS.
I GPUN UTILIZED CONSERVATIVE CAILULATIONAL ASSUMPTIONS, I.E.
' MORE RESTRICTIVE THAN DESIGN BASIS REQUIRED PARAMETERS.
GPUN PREVIOUSLY (PRIOR TO 1HRO1TLING THE VALVES) AND WITH
FORETHOUGHT, EVALUATED THE OPERATION OF THE ESW/CS I SYSTEMS WITH ESW DISCHARGE VALVES THRO 1TLED.
- APPROPRIATE AND TIMELY ACTIONS WERE TAKEN IN THE DECISION TO THRO 1TLE THE ESW DISCHARGE VALVES.
- THeRe iS NO VIOLATION ASSociATEo Wilm THiS ISSUE iNo NO SAFETY SIGNIFICANCE.
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_ . '[[ s.- ATTACHMENT IV , i ' Safeguards Meeting Attendees GPU Personnel ', - R. Ewart, Security Lt.
' - M. Heller, Licensing Engineer , . J. Knubel, Security Director , l NRC Personnel , R. Albert, Region I, Physical Security Inspector
T. Dexter,. Region I, Physical Security Inspector > D. Lew, Resident Inspector, Oyster Creek B. Manili, NRR, RSGB G. Smith, Region I, Senior Physical Security Specialist E. Sylvester, Region I, Sr. Reactor Engineer, Physical Security
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