ML20235E532
| ML20235E532 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 09/23/1987 |
| From: | Shelton D TOLEDO EDISON CO. |
| To: | NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| 1423, GL-87-12, NUDOCS 8709280157 | |
| Download: ML20235E532 (28) | |
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[419]249 2399 Docket No.'50-346 License No. NPF-3 Serial No. 1423 September 23, 1987 United States Nuclear Regulatory Commission Document Control Desk Washington, D. C.
20555 Gentlemen:
Pursuant to 10CFR50.54(f), enclosed is Toledo Edison's response to NRC Generic Letter 87-12, Loss of Residual Heat Removal while the Reactor Coolant System is partially filled.
Very trul yours, J
CAB: pig cc: DB-1 NRC Resident Inspector A. B. Davis, Regional iministrator (2 copies) l l
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THE TOLEDO EDISON COMPANY EDISON PLAZA 300 MADISON AVENUE TOLEDO, OHIO 43652 4
8709280157 870923 PDR ADOCK 05000346 P
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, Docket No. 50 346, License'No. NPF-3 l
Serial.' No..~ 1423 Enclosure.
l RESPONSE TO GENERIC LETTER 87-12, j
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" LOSS OF RESIDUAL H'
.0 VAL (RHR) WHILE THE'
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REACTOR COOLANT SYSTEM (RCS) IS PARTIALLY FILLED",
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FOR
.l DAVIS-BESSE NUCLEAR POWER STATION UNIT NO. 1 Attached is Toledo Edison's response to Generic' Letter 87-12, Loss of Residual Heat Removal while the Reactor Coolant System is partially-filled. This response is. submitted. pursuant to 10CFR50.54(f).
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D. C. Shelton, Vice PresicTent, Nuclear 4
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Sworn to and subscribed before me this 23rd day of September, 1987.
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Notary Public, State of Ohio I
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My commission expires V,/8
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Docket No. 50-346 j
License No. NPF-3 Serial No. 1423 l
Attachment Page 1 RESPONSE TO GENERIC LETTER 87-12, LOSS OF RESIDUAL HEAT REMOVAL (RHR)
WHILE THE REACTOR COOLANT SYSTEM (RCS) IS PARTIALLY FILLED 1.
A detailed description of the circumstances and conditions under which your plant would be entered into and brought through a drain-down process and operated with the RCS partially filled (1.A),
including any interlocks that could cause a disturbance to the system (1.B).
Examples of the type of information required are the time between full-power operation and reaching a partially filled condition (used to determine decay heat loads) (1.C.1); requirements for minimum steam generator (SG) levels (1.C.2); changes in the status of equipment for maintenance and testing and coordination of such operations while the RCS is. partially filled (1.C.3); restrictions regarding testing, operations, and maintenance that could perturb the nuclear steam supply system (NSSS) (1.C.4); ability of the RCS to withstand pressurization if the reactor vessel head and steam genurator manway are in place (1.C.5); requirements pertaining to isolatfon of containment (1.C.6); the time required to replace the equinatat hatch should replacement be necessary (1.C.7); and requiremen. pertinent to reestablishing the integrity of the RCS pressure boundary (1.C.8).
Response
1.A The Davis-Besse Nuclear Power Station, Unit No. 1, vould enter into a draindown process and operate with the Reactor Coolant System (RCS) partially filled during refueling operations, or maintenance activities when the RCS temperature is less than or equal to 140*F.
The RCS could be drained down for work on numerous components. System Procedure 1103.11, Draining and Blanketing of the RCS, provides for draining, nitrogen blanketing, and maintaining the proper level in the RCS during refueling and/or during the following example maintenance activities:
RX VESSEL LEVEL CONDITION (distance above 36" Hot Leg Center Line)
- a. Reactor Head Removal 80" ! 2"
- b. Control Rod Drive Removal 80" 2"
- c. Reactor Internal Vent Valve Removal 80" 2"
- d. Incore Monitor Piping Repair 80" 2"
- e. Reactor Coolant Pump Maintenance 18" 2"
such as rotating assembly replacement
4-
- Dockat No. 50-346 License No. NPF-3
- Serial No. 1423 L
Attachment Page.2-RX VESSEL LEVEL (distance above 36" CONDITION.
Hot Leg Center Line)
'f.; Reactor' Coolant Pump. Seal Replace-40" to 54" ment
- g. Pressurizer Relief Valve Removal-56'
- h. Reactor. Coolant Hot Leg 5 6
' Temperature Detector Well Removal
- 1. Steam Generator' Tube Plugging.
'18" i 2"
'j. Pressurizer Heater' Removal.
- 5' 2
-k.-Reactor Coolant Cold Leg Temperature 11" 1 1" Detector Well Removal
- 1. Core Flooding Check Valve Internals 14" 2"
Maintenance
- m. Leak Checking once Through Steam 53' 7.5" or 59' 4.5" Generator Tubes (corresponds to station elevation 624' 7'5" or 630' 4.5")
Reactor Coolant from the RCS is drained to the Reactor Coolant Drain Tank and then pumped to the Clean' Liquid Radwaste System.
Water is' stored in the Clean Waste Receiver Tanks until it is' needed to refill the RCS, Nitrogen is used-during the draining process to maintain positive pressure to assure a vacuum is not created. The nitrogen also serves as a blanket for the RCS during low level operation.
1.B The following is a list of the three interlocks which could potentially cause a disturbance to Decay Heat Removal (bHR) operation:
a.
Interlocks associated with the RCD boundary valves that provide the suction flowpath for DHR operations, DH 11 and DH 12.
DH 11 (via a Safety Features Actuation System (SFAS) bistable) and 141 12 (via PSH RC 2B4) would automatically close on high RCS pressure (approximately 300 psig) to prevent over pressurizing the DHR system. However, Technical Specifications 3/4.4.1.2 and 3/4.4.2 and Plant Procedure 1102.10, Plant Shutdown and Cooldown, require removal of control power from DH 11 and DH 12, once they are opened.
This prevents inadvertent closure of DH 11 and DH 12 while the DHR system is in operation.
In addition, plant over-
. pressure protection is provided at low temperatures via the DHR suction line relief valve, DH 4849. Therefore, the interlock associated with the RCS boundary valves providing the suction flowpath for DHR operations is not a problem.
Dockst No. 50-346 License No. NPF-3 Serial No. 1423 Attachment Page 3
.b.
An interlock associated with decay heat pump (DHP) suction valves from the RCS, DH 1517 and DH 1518 (downstream of DH 11 and DH 12), and the emergency Low Pressure Injection (LPI) suction valves, DH 2733 and DH 2734 (suction from the Borated Water Storage Tank.(3WST)/ emergency containment sump).
If DHR Train 2 was lined up for DHR with DH 1518 open and DH 2734 closed (normal DHR lineup), and a spurious SFAS level 3 signal was received, DH 2734 would open and DH 1518 would close causing a loss of DHR operation. However, Plant Procedure 1102.10, Plant Shutdown and Cooldown, requires closing DH 2734 and opening its associated breaker prior to opening DH 1518. Therefore, any SFAS signal received would not cause DH 2734 to open.
(This same condition applies to DHR Train 1.)
c.
The SFAS level 3 signal actuates various DHR system components.
If a DHR train is lined up for DHR, and an SEAS level 3 nignal was received, DH 1517 and DH 1518, DH 1A and DH IB, DH1! and DH 12 would not be affected because these valves are not actuated by an SFAS signals.
A spurious SFAS signal could cause a DHP suction valve re-alignment resulting in a loss of DHR. Per the discussion in response 1.B.b, this is prevented by procedural require-ments removing power from the appropriate BWST/ containment emergency sump suction valve. Since the appropriate BWST suction valve is closed and de-energized, opening of its associated BWST outlet valve (DH 7B or DH 7A) is not a concern.
An SFAS signal could cause the DH cooler throttle valves to go to their failed positions; the DH cooler bypass valves would go shut and the DH cooler throttle valves would go open. This could cause an increase in DHP flowrate and cooldown rate. However, the SFAS signal could be blocked and the DH cooler bypass and outlet valves re-positioned to regain control.
Therefore, the above mentioned interlocks would not cause a loss of DHR operation.
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Dockat No...50-346 License No. NPF-3 Serial No.'1423 Attachment Page 4 l
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l 1.C.1 Plant Procedure 1102.10, Plant Shutdown and Cooldown,. restricts-
'the maximum cooldown rate between full power operation and beginning of RCS drainage to 100'F/hr, although average cooldown l
rates are much less than 50*F/hr. The minimum. time between full power' operation and reaching a partially filled RCS condition, assuming ideal conditions, could be approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
However,'a much more realistic value, based on past shutdowns, cooldowns and'draindowns is on the order of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Figure 1, Decay Heat vs. Shutdown Time, can be used to determine DH. loads. This curve assumes worst case heat loads based on 380 effective full power' days-(EFPDs) at 100% full power. The data was generated from guidance provided in ANS/ ANSI 5.1-1979, " Decay Heat' Power in Light Water Reactors".
Figure 2, Required Tubeside Flowrate vs. Heat Load, shows the required flow rate through the primary side (tubeside) of the DH cooler as a function of the DH load. This data was provided by the manufacturer for a given she11 side flowrate of 6000 gpm and a tubeside inlet temperature of 140'F.
Figure 3, Predicted Total DH Flow vs. Reactor Water Level, is based on plant specific data. This figure shows the required RCS level when operating f
the DH coolers such that vortexing of the pump does not occur for the-given flowrates.
By:first obtaining the DH load from Figure 1, based on the number of days after shutdown, the required flowrate can be obtained from Figure 2.
Figure 3 then provides for the' minimum RCS level based on the required flowrate such that vortexing of the pump does not occur. These figures provide the required information of RCS level vs. heat load based on days after shutdown.
1.C.2 For the secondary side of the OTSGs, there are no requirements for minimum level while in a drained down condition. As out-lined in System Procedure 1106.08, Steam Generator Secondary Side Fill, Drain and Layup, the normal condition during shutdown is the wet layup recirculation mode. The secondary side is filled to the upper tubesheet, with the level maintained at approximately 620 inches on the Full Range level instrument.
Docket No. 50-346 License No. NPF-3 Serial No. 1423 Attachment Page 5 i
This ensures the upper tubesheet is covered with water and a nitrogen blanket is not required. The only time this level is reduced is for maintenance.
For the primary side (RCS) of the OTSGs the RCS water level remains i
above the top of the fuel while the OTSGs are drained below the lower tubesheet for:
1.
Steam Generator Tube Plugging 2.
Reactor Coolant Cold Leg Temperature Detector Well Remeval 3.
Core Flood Check Valve Internals Maintenance 4.
RCP Maintenance such as rotating assembly replacement 1.C.3 A Plan of the Day meeting which includes representatives from various maintenance departments, operations and other depart-ments is currently held each weekday morning.
Significant maintenance activities are discussed during these meetings.
With the recently expanded outage management department and the outage management scheduling system, more people are aware of maintenance being performed and the impact on plant operations and conditions. All work orders are pre-approved by current 4-or previously licensed Senior Reactor Operator, k
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Additionally, work that has the potential of affecting the RCS while in a drained down condition must be approved by the Shift i
Supervisor. He is the only individual who can approve tests and maintenance work in the plant.
l 1.C.4 The following list of Technical Specifications provide restric-tions regarding testing, operations, and maintenance of the DHR trains that provide assurance that such perturbations to the NSSS do not occur:
a.
TS 3.1.1.2, Boron Dilution (requires, in all Modes, the flow rate of reactor coolant through the RCS to be greater than or equal to 2800 gpm whenever a reduction in the RCS boron concentration is being made).
b.
TS 3.1.2.1, Boration Systems, Flow Paths - Snutdown (requires, in Modes 5 and 6, at least one of the following boron injection flow paths to be operable:
a) A flow path from the concentrated boric acid storage system via a boric acid pump and a makeup pump or DHP to the RCS, if only the boric acid storage system is operable; or b) A flow path from the BWST via a makeup pump or DHP to the RCS, if only the BWST is operable).
s
Docket No. 50-346.
License No.'NPF-3'
-Serial No. 1423 Attachment l
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'Page.6 Ji 1
c.
TS 3.4.1.2, Coolant Loops and Coolant Circulation, Shut-down and. Hot Standby (requires, in' Modes 3, 4 and 5, two of the following coolant loops to be operable:- 1) RC Loop 1 and;its' associated steam generator; 2) RC Loop'2 and its associated steam generator; 3) DHR Loop 1; and 4) DHR Loop 2)..
d.
TS 3.4.2, Safety Valves - Shutdown.(requires,s in Modes 4-and 5, the DHR system relief valve _ (DH 4849) to be ' operable, and the RCS suction isolation valves be open and.the control-power toL their valve operators removed).
e.
. less than 280*F (requires, in Mode 4, one ECCS subsystem"E6 be-operable, and comprised of:
An operable flow path capable of taking suction from the :
BWST and manually transferring suction to the containment emergency sump during the recirculation: phase'of opera-tion).
f.
TS'3.9.8.1, Decay Heat Removal and Coolant Circulation, All Water Levels (requires, in Mode 6 when the water level above the top of the irradiated fuel assemblies seated
.within the reactor pressure vessel.is greater than or equal to 23 feet, at least one DHR. loop to be in operation).
g.
TS 3.9.8.2, Decay Heat itemoval and Coolant Circulation, Low Water Level (requires, in Mode 6 when the water level above the top of the irradiated fuel ccecmblies seated within the reactor pressure vessel is less than 23 feet, two independent DHR loops.to be operable with one DHR loop to be in-operation).
_ System Procedure 1104.04, Decay Heat and Low Pressure Injection Operating Procedure, and System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, provide the following precautions to ensure proper operation of the DHPs:
a.
Maintain the RCS level high enough to prevent DH suction line vortex formation and provide adequete net positive suction head for the pumps.
b.
If the RCS is partially drained and DH flow is through the bypass line only, via DH 21 and DH 23 (bypass valves around DH 11 and DH 12) maintain DH flow less than 4000 gpm to prevent losing net positive suction head.
c.
Maintain nitrogen pressure positive and as close to O psig as possible to ensure proper level indication.
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t Docket No. 50-346 License No. NPF-3 l
Serial No. 1423 Attachment Page 7 i
d.-
When draining the RCS to low levels, caution statements ensure adequate pump net positive suction head and cavi-tation/vortexing protection.
System Procedure 1104.04, Reduced RCS Water Level Operations, recommends having the second train of DHR lined up for LPI. If I
suction is lost to the operating DHP for any reason, since the second train of DHR would be lined up to the BWST, DHR should not be affected and, be available to maintain core cooling.
1.C.5 RCS pressure is limited to 320 psig when aligned for DRR system operation. This pressure limitation corresponds to the DH i
suction line relief valve setpoint. This valve is installed to ensure DHR system piping remains within the design pressure i
limits and to provide RCS low temperature overpressure protection.
l The setpoint and valve sizing preclude the possibility of RCS pressure boundary failure at any permissible low temperature with maximum flow occurring from the high pressure injection pump.
The vertical OTSG design, unlike the U-tube design, will prevent accumulation of air / vapor within the primary side of the OTSG permitting it to pass through to the high point vents for removal from the system.
1.C.6 Other than the Technical Specifications required in Modes 1-4 and Mode 6 during refueling, there are no specific restrictions on containment isolation during low RCS level operation.
1.C.7 TS 3.9.4, Containment Penetrations, requires the equipment hatch to be closed and held in place with a minimum of four bolts during core alterations or movement of irradiated fuel within the containment. The equipment hatch can be secured in place (i.e., with a minimum of four bolts) in approximately 30-45 minutes.
1.C.8 There are no requirements pertinent to re-establishing the integrity of the RCS pressurf boundary. However, adequate precautions are taken to maintain integrity of the RCS pressure boundary. As an example, during the May 1987 outage, CF 30 (RCS pressure boundary check valve) was repaired. A temporary cover for CF 30 was fabricated for installation when physical work was not being performed on CF 30, thereby ensuring the integrity of the RCS pressure boundary.
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f, pocket No. 50-346 Licenta No. NPF-3 FIGURE 3 Serial No. 1423 PREDICTED TOTAL DH FLOW VS.
REACTOR WATER LEVEL 5000 -
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10 20 30 REACTOR WATER LEVEL (inches above the 36" hot leg center line)
' Docket No. 50-346 License No. NPF-3 Serial No. 1423.
Attachment Page 8 i
2.
A' detailed description of the instrumentation and: alarms provided'to.
the operators for controlling thermal and hydraulic aspects of the-
- NSSS during operation with the.RCS partially filled (2.A)..You should describe' temporary connections,. piping, and instrumentation.
-used for this RCS condition (2.B) and the quality control process co ensure proper functioning of such" connections, piping and'instrumen-tation, including assurance that they do not contribute to loss of RCS inventory or otherwise lead to perturbation of.the NSSS while the
'RCS.is partially filled (2.C).
You should'also provide a description of your ability to monitor RCS pressure, temperature, and level after the RHR function may be lost (2.D).
Response
2.A Table 1, RCS. Instrumentation and Alarms, provides a description
'of the instrumentation and' alarms provided to the operators for controlling thermal and hydraulic aspects of the NSSS during operation with the RCS partially filled.
2.B Temporary connections, piping and instrumentation used-for this RCS condition are described below:
A reactor refueling level indicator (LI 214) with a range of 0 - 40 feet is used during low RCS levels. This is a permanent connection, although it is valved out during non-drained down l
conditions.. The stainless steel Barton Cauge is a bellow type with 0.1 feet increments. Zero on the level indicator corres-l ponds to the center line of the reactor vessel's 36-inch inside L
diameter hot leg piping. The indicator is' located outside of the secondary shielding inside containment. The reactor refueling level indicator is placed in service when the pressurizer level reaches 28 inches. When the RCS level is decreased to approxi-mately 29 feet as indicated on LI 214, corresponding to an indicated pressurizer level of approximately 0 inches, the control room operators monitor RCS level (LI 214) via a control room Closed Circuit Television (CCTV) monitor which is focused on the RCS water level indicator in containment.
l-In addition to LI 214, a tygon tubing level indication, with a range of 0 - 120 inches, is utilized when the level on LI 214 is less than eight feet. The tygon tubing also uses the reactor vessel-hot leg centerline as the zero reference point and is attached to a pressure test connection, LP 214, with the other end open to containment atmosphere. A secured measuring device is installed at the tygon tubing to provide referenced level indication and accurate reading capability. The control room CCTV is then focused on the tygon tubing. RCS level is clearly indicated on the CCTV monitor in the control room using the tygon tubing level indication.
Equipment operators periodically make rounds in containment to locally verify the level of LI 214 and the tygon tubing.
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License No. NPF. Serial.No.'1423 Attachment
'Page 9 The reactor coolant level-in the OTSGs are read out on sections of tygon tubing 40 feet long which are installed at reactor L
coolant cold leg pressure test connections (PP 218 or PP 219
.for OTSG 1-1 and PPl 203 or PP 204 for OTSG 1-2) and the other p
end is open to containment atmosphere. This indication is
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utilized when the RCS level is.between 0-32 feet (LI 214
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indication). A section of the tygon tubing may be attached at i
each of the four reactor coolant cold leg pressure test connec-tions..In accordance with System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, a section of'tygon tubing is installed on the affected loop and on one of the loops of the unaffected 0TSG during reactor coolant pump (RCP) seal replace-ment, RCP. repair, core flood check valve internals maintenance, steam generator tube plugging, and other. work where low OTSG 1evel is needed.
Periodic Test 5183.05, OTSG Tube Leak Test, provides the procedure for.1.eak checking OTSG tubes. A section'of tubing 100 feet in ichgth is installed at one of the reactor coolant cold leg pressure test connections of the OTSG being tested. The tygon tubing is suspended above the top of the hot leg and open to the contaimrent atmosphere. The affected OTGGs upper tube sheet is used as the zero reference point. This indication will only be used for levels one to eight feet below the zero reference point.
The DHP suction pressure is observed by an Equipment Operator stationed near the pump. When RCS level is less than 36 inches above the center line of the hot leg, a temporary pressure gauge is routed near a phone line so the Equipment Operator is able to notify the control room immediately of any DHP suction pressure changes. or any other DHP problems.
Suction pressure changes may be indications of possible vortexing or net positive suction head problems. System Procedure 1104.04, Decay Heat and Low Pressure Operating Procedure, requires the suction pressure to be maintained at 3.7 psig or greater.
During RCS draining, calibrated pressure gauges are installed on top of each RCS hot leg loop to monitor individual RCS hot leg pressure, and on the pressurizer vent line to monitor pressurizer pressure. Wide range (-30 inches Hg to 60 psig) and narrow range (-10 inches Hg to 5 psig) gauges are utilized during the draining process. The wide range gauges are used until RCS pressure reaches five psig. At five psig, the narrow range gauges are placed in service. An operator is stationed at each gauge during draindown to assure a vacuum does not develop. This is accomplished by controlling the nitrogen pressure at each of these points between 0-0.5 psig. The wide range gauges are placed back into service when the RCS is filled and vented.
- _ _ _ =
Dockst No. 50-346 License No. NPF-3 Serial No. 1423 Attachment Page 10 The RCS is vented to containment via polyethylene f11tered bottles. The filters trap moisture and contaminants before the gas vents to containment. Two bottles are connected to the control rod drive penetrations when the RCS is drained to 80 1 2 inches. A bottle is also connected to each hot leg and the pressurizer to assure RCS pressure is maintained at containment pressure.
2.0 The following is a list of quality control processes to ensure i
proper functioning of the cited connections, piping and instrumen-tation:
a.
System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, requires calibrating LI 214 prior to placing it in service, b.
System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, requires enlibrating the pressure gauges prior to installation on the pressurizer and individual RCS hot legs.
c.
Operators check LI 214 and the OTSG levels indicators periodically when they are being used. These are checked for leakage, level consistency, etc.
d.
Per System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, the tygon tubing is placed in service when the RCS level is lowered to eight feet as indicated on LI 214.
e.
A secured measuring device is installed with the tygon tubing to provide a referenced level indication. The control room CCTV is then focused on the tygon tubing. RCS level is clearly indicated on the CCTV monitor in the control room using the tygon tubing level indication.
2.D Instrumentation used to monitor RCS pressure, temperature and level is shown in Table 1.
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l Dockst No. 50-346 License No. NPF-3 Serial No. 1423 Attachment Page 11 3.
Identification of all pumps that can be used to control NSSS inventory include: a) pumps you require be operable or capable of operation (include information about such pumps that may be temporarily removed from service for testing or maintenance);
b) other pumps not. included in Item a (above); and c) an evaluation of items a and b (above) with respect to applicable TS requirements.
Response
3.A TS 3.9.8.1, Decay Heat Removal and Coolant Circulation, All Water Levels, requires, in Mode 6 when the water level above the top of the irradiated fuel assemblies seated within the reactor pressure vessel is greater than or equal to 23 feet, at least one DHR loop to be in operation.
TS 3.9.8.2, Decay Heat Removal and Coolant Circulation, Low Water Level, requires, in Mode 6 when the water level above the top of the irradiated fuel assemblies seated within the reactor pressure vessel is less than 23 feet, two DHR loops to be operable and one DHP to be in operation.
System Procedure 1104.04, Decay Heat and Low Pressure Injection Operating Procedure, requires the DHPs to be operable /in opera-tion as required, during these low level operations.
Curve CC 6.4 (Figure 3) is provided in plant Procedure 1101.07, Miscel-laneous Operation Curves, for guidance while operating the DHR system at low water levels. This curve can be used to estimate the total DH flow based on various reactor water levels.
3.B Other pumps which may be used to control RCS inventory, as identified in Abnormal Procedure 1203.35, Loss of Decay Heat Removal System, include:
a) HPI Pumps b) Makeup System Pumps c) Spent Fuel Fool Pumps d) BWST Recirculation Pump e) Clean Waste Receiver Tank Pumps f) Clean Waste Monitor Pumps g) Boric Acid Addition Pumps h) Primary Transfer Pumps i) Refueling Canal Transfer Pumps j) Demineralized Water Pumps 3.C TS 3.1.2.1, Boration Systems, Flow Paths - Shutdown, requires, in Modes 5 and 6, at least one of the following boron injection flow paths to be operable:
a) a flow path from the concentrated boric acid storage system via a boric acid pump and a makeup pump or DHP to the RCS, if only the boric acid storage system is operable; or b) a flow path from the BWST via a makeup pump or DHP to the RCS, if only the BWST is operable.
t Dochat No. 50-346'
. License No. NPF-3 Serial No. 1423 Attachment-Page 12
- TS 3.1.2.5, Decay Heat Removal Pump - Shutdown, requires, in Modes 4,'S & 6 with RCS pressure less than 150 psig, at least
- one DHP in the boron injection flow path to be operable and capable of being powered from an operable essential bus.
TS 3.1.2.6, Boric Acid Pump - Shutdown,' requires, in Modes 5 &
6,'at least one boric' acid pump to:be, operable and capable of being powered from an operable essentfal bus'if only the' flow-path through the boric acid. pump is operable.
TS.3.1.2.8, Borated Water Sources - Shutdown, requires,'in Modes'5 & 6, as a minimum, one of the following borated water sources to be operable:
a) A boric acid addition system with:
- 1. A' minimum contained borated water volume; 2. Between 7875 &
13,125 ppm.B;!and 3. A minimum solution temperature of 105*F; b)
The BWST with:
- 1. A minimum-contained borated water volume of 70,700 gallons; 2. A minimum boron concentration'of 1800 ppm;.
. and 3.'A minimum solution temperature of 35"F.
Dockst'No. 50-346 Licznsa No NPF-3 S2 rial No. 1423 Attachment Page 13 4.
A description of the containment closure condition you require for the conduct of operations while the RCS is partially filled.
Examples of areas of consideration are the equipment hatch, personnel hatches, containment purge valves, SG secondary-side condition upstream of the isolation valves (including the valves),
piping penetrations, and electrical penetrations.
Response
TS 3.9.4, Containment Penetrations, requires, during core alterations or movement of irradiated fuel within the containment, the containment penetrations to be in the following status:
- 1) The equipment door be closed and held in place by a minimum of four bolts; 2) A minimum of one door in each airlock be closed; and 3) Each penetra-tion providing direct access from the containment atmosphere to the outside atmosphere to either: 1) Be closed by an isolation valve, blind flange, or manual valve; or 2) Be capable of being closed by an operable automatic containment purge and exhaust isolation valve.
. Electrical penetrations have a nitrogen cover pressure to maintain integrity.
In Mode 6, per the requirement of TS 3.9.9, Containment Purge &
Exhaust Isolation System, System Procedure 1104.21, Containment Purge System Procedure, and Abnormal Procedure 1203.38, Fuel Handling Acci-dent, the Containment Purge valves are required to automatically close on an SFAS level 1 signal during fuel handling.
Also, see response to 1.C.6.
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Docket No. 50-346-
. License No. NPF-3 Serial No. 1423
- Attachment.
Page'14 5.
Reference to and'a summary description of procedures in the control room of your plant which describe operation while the RCS is partially filled (5.A.1)...Your response should include the analytic basis you used'for procedures development (5.B). ~We are particularly interested in your treatment of draindown to the condition where the RCS is partially filled, treatment of minor variations from expected behavior such as caused by air entrainment and'de-entrainment (5.A.2),
treatment of boiling in the core with and without RCS pressure
. boundary. integrity (5.A.3), calculations of approximate time from loss of RHR to core damage (5.A.4), level differences in the RCS and' the effect upon instrumentation indications (5.A.5), treatment of air
-in the RCS/RHR system (5. A.6), including the impact of air upon NSSS and instrumentation response, and treatment of vortexing at the connection.of the RHR suction line(s) to the RCS (5.A.7).
Explain how your analytic basis supports the following as pertaining to your facility: a) procedural guidance pertinent to titing of operations, required instrumentation, cautions, and critical para-meters; b). operations control and communications requirements regarding operations that may perturb the NSSS,' including restric-tions upon testing, maintenance, and coordination of operations that could upset the condition of the NSSS; and c) response to loss of RHR, including regaining control of the RCS heat removal, operatons invol-ving the NSSS if RER cannot be restored, control of effluent.from the containment if containment was not in an isolated condition at the time of loss of RHR, and operations to provide containment isolation if containment was not isolated at the time of loss of RHR (guidance pertinent to. timing of operations, cautions and warnings, critical parameters, and notifications is to be clearly described) (5.C).
Response
5.A.1 The plant is shutdown and cooled via Plant Procedure 1102.10, Plant Shutdown and Cooldown. Between 340*F and 280*F (observing proper pressure requirements) DH 11 and DH 12 are opened to place DH 4849 (DH Suction Line Relief Valve) in service. Both trains of DHR are in LPI alignment (DHP suction aligned to the BWST) until RCS temperature is less than 280*F and one train of DHR is in the LPI alignment until RCS temperature is less than 200*F.
Plant Procedure 1102.10, Plant Shutdown and Cooldown, provides the appropriate instructions to place the DHR system in operation, and references System Procedure 1104.04, Decay Heat and Low Pressure Injection Operating Procedure, to control flow and temperature within the given limitations. After the RCPs are stopped, natural circulation is utilized to cooldown the loops. When the RCS reaches 140*F, the cooldown is considered complete.
Dockat No. 50-346 License No. NPF-3 Serial No. 1423 Attachment Page 15 When the RCS is drained for maintenance, System Procedure 4'
1103.11, Draining and Nitrogen Blanketing of the RCS is utilized.
The procedure is divided into various sections to provide procedures for draining, nitrogen blanketing, and maintaining the proper level in the RCS during refueling and/or particular I
maintenance. It also specifies conditions such as RCS cooldown i
temperature, pressurizer level, nitrogen system requirements, and tygon tubing installation requirements, and provides the methodology to reduce the RCS water level.
System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, also references System Procedure 1104.04, Decay Heat and Low Pressure Injection Operating Procedure, which provides the procedure for the operation of the DHR system during reduced RCS water level operations.
4 5.A.2 System Procedure 1103.11, Draining and Nitrogen Blanketing of the RCS, provides the following caution for 18 inch, 14 inch and 11 inch RCS levels to protect the DHPs from cavitation and vortexing during draindown to low RCS water levels:
" CAUTION: It is absolutely necessary to protect the decay heat pumps from cavitation and vortexing. Refer to Decay Heat and Low Pressure Injection Operating Procedure, System Procedure 1104.04, Section 5. for decay heat pump operating precautions."
5.A.3 Boiling within the RCS is addressed in Abnormal Procedure i
1203.35, Loss of Decay Heat Removal System. Section 4.2, Operator Response Time, identifies a time of 27 minutes, after the reactor has been shut down for at least two days and the RCS vater level is located at approximately the reactor vessel flange, for the water in the reactor to reach the boiling pcint after a loss of all DH flow. This time corresponds to worst case conditions of an open RCS. Figure 4 represents the time to boil based on decay heat loads generated for Figure 1.
This data is based on the time to heat up and boil off the water only; it does not include the time to heat up the reactor vessel or internals.
5.A.4 Abnormal Procedure 1203.35, Loss of Decay Heat Removal System, Section 4.2, Operator Response Time, identifies a time of approximately two and a quarter hours after boiling has started for the water level to boil down (at a rate of 82 gal / min) to I
the top of the core at which time inadequate core cooling
(
exists. This time correspor.ds to worst case conditions of an open RCS.
Figure 4 also represents the time to core uncovery based on the decay heat loads generated foi Figure 1.
This data l
1s based on the time to heat up and boil off the water only; it does not include the time to heat up the reactor vessel or internals.
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!q Dock'st No.50-34E T
Licenne No..NPF-3 Serial No. 1423 Attachment 1
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.Page 16 H
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5.A.5' Step {.2.6ofSystemProcedure 1103.11, Draining and %ttrogen Blanketitg o,'
the'RCS, provides instructions to equalize level
'todraining(celow80 inches.
and pressur between both'RCS loops and the pressurizer prior The configuration had derign I
of the. Davis-Besse RCS permits uniform icvel control during draindown ecnditions with no inherent instabilities.
t Due to the vertical once-through steam generator design, along with several.high point vents and cold leg drains, the effects'of prersure or level changes on indicated
,o icvel are minimized.
Unlike the U-tube steam generators, there is,no threshold water level at which generator' tube-draining' Is indicated since air or nitrogen for venting enters.from above. Since the reference leg of the temporary level indicator is gented to the containment atmosphere, the system may be susceptible to inaccurate readings if RCS level or pressure, or containment pressure, changes gore rapidly than can be accommodated by the venting system.
S.,1.6 During pre-operational testing, the concern of operating the DHR and system at RCS reduced water levels was addressed. A speciel s
S.A.7 test was'run to address vortexing/ air entrainment concerns to determine propfr DHP operation, including throttling DH flow 'to i
prpvent adverse effects from these phenomena.
th c curves were developed for guidance while operating DH at i
icw' water levels and are provided in Plant Procedure 1101.07, Miscellaneous Operation Curves. Curve CC 6.4 (Figure 3) can by
.used to estimate the total decay heat flow vs. reactor water Invel. At approximately 18 inches above the center line of the RCS hot leg, DHP operation may be affected by vortexing. This curve serves as a guide to show what flow rate was possible at Serious levels during pre-operational testing. Curve CC 6.2 shows the minimum suction pressure that should be maintained on (the cuction gauge. As long as the pump performance for the f1'w s
o
+
0 yate is consistent with the pump curve and no unusual noise or i
discharge pressure variation is observed, pump operation can continue.
Surveillance Test 5051.10, DH/LPI Pump and Check Valve Test, provides for stationing a watch at the pump to note abnormal indications and monitor DHP parameters (inlet pressure, pump w)L differential pressure, flow rate, vibration amptitude, proper
)'
lubricant level, and bearing temperature).
From the historical a
data taken during DHP testing no degradation of the DHP opera-
.\\[
J't tion has been noted.
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~Dockat No. 50-346
' License No. NPF-3 l Serial No. 1423
' Attachment Page 17:
' Abnormal Procedure 1203.35, Loss of Decay Heat Removal System, has been developed to respond to a loss of DHR. This procedure includes venting of'the DHR system high point and starting of the second DHP aligned in the LPI mode with pump suction aligned to the BWST. System Procedure. 1104.04, Decay Heat and Low Pressure Injection Operating Procedure, Section 5, Decay Heat Removal During'RCS. Component Repair, recommends aligning the other DHP to supply LPI from the BWST if the DHP in operation should fail and DHR could not be re-established prior to core heatup. Therefore, in this lineup, the second DHR train would be unaffected by any vortexing/ air entrainment phenomena affecting the first DHR train operation. By maintaining an independent suction for each DHR train, the core would be kept covered.until DHR is-restored by Abnormal Procedure 1203.35 Loss.of Decay Heat Removal System.
5.B The inservaentation, level and air entrainment effects described dr., response 5.A have not been quantified analy-tically.. However, pre-operational testing has determined maximum allowable DHR flow rates corresponding to the various reduced RCS water levels in order to preclude the possibility of vortexing. The times provided for core heatup to boiling and the onset of core damage are calculated values.
5.C.1 Numerous cautions and instructions are provided in the procedures which control low level operations in an effort to prevent
=
adverse occurrences from loss of DHR from developing. Section 5 of System Procedure 1104.04, Decay Heat and Low Pressure Injec-tion Operating Procedure, addresses this mode of operation and provides strict instructions for avoiding vortexing or DHP cavitation by monitoring RCS level, pump flow rate, DHP suction pressure, DHP suction temperature and other such vital l
parameters. Should a loss of decay heat occur despite these conditions, Abnormal Procedure 1203.35, Loss of Decay Heat l
Removal System, emphasizes the urgency of either restoring normal DER flow or using one of several identified means for providing makeup water to the RCS to preclude core damage. The l-minimum time at which core damage could occur is provided to the operators within the procedure to reinforce the critical nature of restoring core cooling.
These procedural requirements and guidance are based on a combination of analysis, pre-operational testing, vendor recommendations, experience, testing and prudent operating practice. Detailed analysis has not specifically been prepared in support of each item.
Dockat"No. 50-346.
License No. NPF-3, Serial No. 1423.
Attachment:
Page 18 J6.
- A brief. description of training provided to operators.and other affected personnel that is specific to the issue of operation while the RCSlis partially filled. We are particularly' interested in such areas as. maintenance personnel training regarding avoidance ~of
. perturbing the NSSS and response to loss of decay heat removal while the RCS is partially filled.
Response
The training provided to operations personnel, specific.to operation while the RCS is partially filled, includes the following:
a.
The DHR; system lesson plan covers limits and precautions associ-ated with' DER cperation with reduced RCS water icvel. Also included in this lesson are the Technical Specifications assoc-istedLwith DHR operability requirements which are dependent on RCS water level. This lesson material is conducted approxi-mately once per. year for Reactor Operator and Senior Reactor Operator license candidates..
1 b.
The loss of DHR lesson plan discusses the indications available
.to diagnose the loss of DHR and the actions required, dependent on equipment availability, to mitigate this transient. This l
1esson material is conducted approximately once per year for Reactor Operator and Senior Reactor Operator license candidates.
.c.
The Technical Specification lesson plan for refueling operations includes DHR and reactor ~ coolant circulation. This lesson includes.the Basis, Limiting Condition for Operation, and Surveillance Requirements associated with operation during low RCS water level conditions. This lesson material is conducted approximately once per year for Rt. actor Operator and Senior Reactor Operator license candidatas.
d.
The Technical Specification program on the computer based education system also includes DHR and reactor coolant circul-ation. This program includes the Basis, Limiting Condition for Operation and Surveillance Requirements associated with operation during low RCS water level conditions. This lesson material is conducted approximately ence per year for Reactor Operator and Senior Reactor Operator license candidates.
e.
The qualification manual for Reactor Operator license candidates includes performance, or simulation, of operation of the DHR system during low RCS water level conditions. This i
practical requirement is completed during the Reactor Operator l
candidates on-the-job training program.
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.Dockst No. 50-346
[:
' License No. NPF-3 Serial No. 1423 Attachment Page 19 f..
The Loss of DHR' Abnormal Procedure contains the indications and actions required to: diagnose:and mitigate a loss of DHR during l
low RCS water' level conditions. This procedure is reviewed on an annual bas'is hy all' licensed. operators.. The required-reading program is utilized to ensure the licensed operators
'are aware'of significant changes to the Loss of DHR Abnormal ~
Procedure.
g.
Non-licensed operator actions for DHR operation on low RCS water level'is discussed in the DHR system lesson plan. This marerial is presented during initial non-licensed operator training and is conducted once every two years as part of the non-licensed l operator requalification program.
Davis-Besse uses a proceduralized work control system to prevent maintenance personnel from perturbing the NSSS during low RCS water level operation. This includes a review by an individual currently l
or previously licensed at the Senior Reactor Operator level of the maintenance work orders for effect on' plant operations prior to submitting the work order to the Operations Department for their review and approval. -Training is conducted on the control of work procedures for maintenance personnel in both the initial and con-tinuing' training programs. Maintenance personnel are also kept informed of significant changes to these procedures utilizing the required reading program.
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Dockat No.'50-346' License No. NPF-3 Serial No. 1423 Attachment Page 20 7.
Identification of additional resources to the operators while the RCS is partially filled, such as assignment of additional personnel with specialized knowledge involving the phenomena and'instrumen-tation.
Response
Control Room operators can call the Reactor _ Performance Engineers at any time, including drained down conditions, to provide technical assistance.
During fuel transfer, the Fuel Handling Director is in constant communication with the control room at all times. This ensures notification of the control room upon loss of RCS inventory.
Additional support can be dispatched in a timely manner through the Plant Duty Roster which assigns specific individuals 24-hour coverage in key positions, l
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Dockst No. 50-346 License No. NPF-3 Serial No. 1423 Attachment Page 21' i
8.
Comparison of the requirements implemented while the RCS is partially filled and requirements used in other Mode 5 operations.
Some requirements used in other Mode 5 operations.
Some requirements and procedures followed while the RCS is partially filled may not appear in other modes. An example of such differ-ences is operation with a reduced RHR flow rate to minimize the likelihood of vortexing and air ingestion.
Response
See response to 5.A.6 and 5.A.7.
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~Dockst No. 50-346 J
L License No. NPF-3 Serial No. 1423 Attachment' i
Page 22 l
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9.
As a result of your consideration of these issues, you may have made changes to your current program related to these issues. If such changes have str*ngthened your ability to operate safety during a partially filled situation, describe those changes and tell when they were made or are scheduled to be made.
3
Response
Procedural changes were previously made to avoid inadvertent inter-locks affecting the DHR function. Plant Procedure 1102.10, Plant Shutdown and Cooldown, was revised following issuance of Amendment 57 to the Technical Specifications (issued May 5, 1983) and requires removing the control power from DH 11 and DH 12, once they are opened, to place DH 4849 (DH suction line relief valve) in service.
(This prevents inadvertent closure of DH 11 and DH 12 and provides plant overpressure protection at low temperatures.)
Plant Procedure 1102.10, Plant Shutdown and Cooldown, was again revised during the 1986 outaFe and now requires closing DH 2733 and DH 2734, and opening its associated breaker, prior to opening DH 1518.
Therefore, any SFAS signal received would not affect inadvertent actuation of DH 2733 and DH 2734.
Due to a previous loss of DHR caused by improper switching of 13.8 KV electrical systems, the 13.8 KV switching procedure was modified to ensure a feed is available to the essential buses at all times.
System Procedure 1104.24, Decay Heat and Low Pressure Injection Oper-ating Procedure, was revised in May, 1987 to expand the section on Precautions and Limitations at reduced RCS water levels.
Abnormal Procedure 1203.35, Less of DHR System, is being revised to clarify and expand the section on venting the DHP after vortexing due to low RCS levels.
_ _ _ _ -