Oconee System

The text in this appendix is directly copied from a document prepared for the Oconee pressurized thermal shock (PTS) study conducted between year 2000 and 2003. It documents the Oconee system at the time of the PTS study.

1. Oconee Unit 1

We are doing Oconee Unit‑1) for our PTS re‑evaluation because:

It was analyzed in the "original" IPTS studies during 1983‑85 (together with the Calvert Cliffs Unit‑1)
We now have already completed its "detailed Fluence maps" thru Brookhaven National Lab.
Its PRA and TH analyses from the earlier IPTS studies should provide guidance and initial data for revising these analyses for our current PTS work

1 Important Aspects of Plant Design and Operation

Oconee has a 2 x 4 lowered loop configuration with two hot legs and four cold legs. It is rated at 2568 MWt. The lowest part of the cold leg is about 6 ft lower than the bottom of the reactor vessel. The reactor coolant pumps are located such that the centerline of the discharge is 3.5 ft above the centerline of the cold leg nozzle. A section of cold leg is sloped at 45 to make up the difference in elevation. The HPI connects to the cold leg in the sloped region of the piping.

Secondary System

Main Feedwater

The main feedwater system includes three parallel motor driven hotwell pumps which raise the pressure to 1.15 MPa (167 psi). There are three motor driven condensate booster pumps that raise the pressure by 2.94 MPa (426 psi) to 4.09 MPa (593 psi). Next are two parallel turbine driven main feedwater pumps, which raises the feedwater pressure to 6.55 MPa (950 psi). The integrated control system controls both the main feedwater pumps speed and the feedwater flow control valves. Separate feedwater flow demand signals are supplied from steam generator A and B. Main feedwater enters the steam generators through a spray header located approximately at the mid-plane of the steam generator.

The main feedwater flow can be realigned to the emergency feedwater piping to fill the steam generator with warm water for less overcooling of the primary system to the natural circulation set point of 60% on the operating range. Automatic overfeed protection is provided by the ICS to trip the main feedwater pumps on high level when the level reaches 96% in either steam generator (at the time of the PTS study it was 90%) of the operating range. Since the time of the IPTS study, an automatic isolation signal was added for main feedwater.

The main feedwater pumps (and turbine driven emergency feedwater pump) will also trip automatically on low steam generator pressure (3.90 MPa, 550 psig). At the time of the IPTS study, there was no automatic trip for main feedwater should a MSLB occur. This was installed subsequently as a result of the study.

Main feedwater does not trip after the reactor trips. The main feedwater pumps continue to supply both steam generators with separate sets of control valves for each steam generator. Both steam generators will have the same post‑trip level set point since the set point only changes depending on whether any reactor coolant pumps are in operation.

During a unit startup or shutdown, that unit's main feedwater pumps turbines are supplied from the auxiliary steam header. The auxiliary steam header is common to all three Oconee units. Each Oconee unit can supply the auxiliary steam header, but normally only one unit supplies it at a time. The unit supplying the auxiliary steam header supplies it from both main steam headers (i.e., from A steam generator and from B steam generator) simultaneously. The auxiliary boiler can also supply the auxiliary steam header.

During normal power operation after the turbine generator is placed on line, the unit's main feedwater pumps are supplied from that unit's 'D' bleed (low pressure extraction steam). 'D' bleed is low pressure extraction steam that is supplied by exhaust from the 8th stage of each of the three low pressure turbines. The "D" bleed steam pressure is higher than the auxiliary steam header pressure.

At high loads, the unit's main steam system supplements the D" bleed. The 'A' main feedwater pump is supplemented by the 'A' main steam header; and the 'B' main feedwater pump is supplemented by the 'B' main steam header.

Each main feedwater pump is equipped with a recirculation line back to condenser. These recirculation lines have automatic valves installed in them which are programmed to ensure at least 2300 gpm flow through the pumps. Therefore, following a reactor trip, when the integrated control system (ICS) sends a signal to ramp the main feedwater control valves shut, the feedwater pumps do not dead head and trip on high discharge pressure.

When main feedwater is supplying the steam generators, the main feedwater pumps supply both steam generators with separate sets of control valves for each steam generator. If any reactor coolant pumps are in operation, the control at the minimum level set point will effectively prevent any difference in the steam generator levels, although there could be different main feedwater flow rates depending on the steam loads for each steam generator.

The main feedwater pumps will trip on high discharge pressure. The A pump set point is 1275 psig, while the set point for the "B" pump is 1240 psig. Therefore, if feedwater pump discharge pressure exceeds 1240 psig, the first feedwater pump trips. This reduces flow and discharge pressure minimizing the possibility of the second feedwater pump tripping.

With all reactor coolant pumps off, there is more chance that one steam generator pressure being lower than the other could result in one steam generator feeding preferentially. However, with all reactor coolant pumps off the main feedwater is directed through the upper auxiliary feedwater header, which has smaller diameter piping and more pressure drop and, therefore, less flow. This will lessen the mismatch in main feedwater flow rates to some extent.

The condenser hotwell pumps remain on following a trip of the main feedwater pumps.

Upon (and only upon) loss of all four reactor coolant pumps, main feedwater is realigned to the upper auxiliary feedwater header. The normal main feedwater nozzles are located at the top of the steam generator downcomer, about 32 feet above the upper surface of the lower tube sheet. The emergency feedwater nozzles are located near the top of the tube bundle, about 47 feet above the upper surface of the lower tube sheet.

The MSLB circuit is described in the Updated Final Safety Analysis Report (UFSAR) on p. 7‑97, December 31, 1999 update. On a low steam generator pressure of 550 psig in either steam generator, both main feedwater pumps are tripped and all main feedwater control and block valves are closed to both steam generators. In addition, the turbine driven emergency feedwater pump is stopped or prevented from starting. These actions are all automatic. The operator is then directed by the emergency operating procedure to identify the steam generator(s) that is (are) causing the overcooling and to manually stop emergency feedwater flow to the steam generator(s). The motor driven emergency feedwater pumps are not controlled by this circuit, and rely on operator action to isolate flow to a steam generator.

The Integrated Control System (ICS) trips the main feedwater pumps automatically on high steam generator level (96% operating range) in either steam generator. The IPTS study used an incorrect value of 90%. Main feedwater pumps also trip on a loss of suction pressure due to a loss of the condensate booster pumps (e.g. on loss of offsite power). Manual isolation of main feedwater following SG overfeed.

Main Feedwater Temperature

After passing through all the feedwater heaters, the feedwater attains a temperature of 511K (460F), which is the temperature at which it enters the steam generators. Steam mixes with the feedwater flow in the downcomer region so the feedwater is close to saturation when it reaches the tube bundle.

Following reactor trip, the turbine trips, the turbine stop valves close and isolate steam flow to the feedwater heaters. The main feedwater temperature will decrease from its initial 100% power value of 455F to the condenser hotwell temperature of 110F as the heating of the feedwater diminishes following turbine trip. The rate that the temperature drops depends on the integrated flow demand.

A typical post‑trip main feedwater temperature response vs. time is shown in Table 7-3. This is based on a Oconee Unit 2 event on 2/28/99. The initial temperature has been adjusted upward from 450F to 455F to be more typical, and the final temperature has been adjusted down to 100F similarly. This data is taken upstream of the steam generators, with approximately 2000 ft³ of water (total) between the temperature sensor and the steam generators. Therefore, your model should either include this volume of main feedwater piping, or the rate of feedwater temperature decrease should be slower by the time it takes for the 2000 ft³ to be purged from the piping for the event being analyzed.

Table 7-3

Post-Trip Main Feedwater Temperature

Time	Main Feedwater Temperature (F)
0 sec	455
600 sec	430
1,200 sec	400
2,400 sec	350
4,200 sec	300
6,000 sec	250
7,800 sec	200
9,800 sec	150
14,400 sec	100

Emergency Feedwater

There are two motor driven pumps and one turbine driven pump. When emergency feedwater is supplying the steam generators, one motor driven emergency feedwater pump is dedicated to each steam generator. The turbine driven emergency feedwater pump is shared to both steam generators. The turbine driven pump cross connects to the discharges of the two motor driven pumps. The emergency feedwater is injecting horizontally through a spray header onto the tube bundle at an elevation near the top of the tube bundle. The emergency feedwater pumps continue running until shut off manually.

Both turbine and motor emergency feedwater pumps start when both main feedwater pumps trip. The emergency feedwater pumps also start on a low steam generator level signal 21 " on the startup range for more than 30 sec. If both main feedwater pumps trip (as indicated by low control oil pressure), the three emergency feedwater pumps start even if the steam generator levels are >21" on the startup range (although feedwater control valves may be closed).

The exception to this is if the main steam line break protection logic has been actuated, in which case the turbine emergency feedwater pump will not start. In steam line break, steam generator pressure will be less than the 550 psig set point, The turbine driven emergency feedwater pump will not start and will be tripped if running.

At the time of the IPTS study the emergence feedwater pumps started automatically if main feedwater pressure drops below 750 psig. This is no no longer so with the 1999 design.

The turbine feedwater pumps will trip when steam generator level 96%operating range. The motor driven emergency feedwater will not trip automatically. They have to be stopped manually by the operator.

We modeled them to be tripped in RELAP5 for the overfeed transients when the operator is supposed to trip them. All emergency feedwater pumps will be started automatically when main feedwater pumps trip. In case of MSLB steam generator pressure will be less than 550 psig so that the turbine-driven emergency feedwater will not start.

The normal suction supply for the emergency feedwater pumps is the upper surge tank rather than the condenser hotwell. The flow is pumped directly to the steam generators, bypassing the feedwater heaters. The minimum temperature is 60F and the maximum temperature is 130F at full power, and 150F at 30% power. The normal temperature range is 90F to 110F. The temperature of emergency feedwater water source is assumed to be 70F in the RELAP calculations.

Therefore, it is possible if steam generator pressures differ that the flow from the turbine driven emergency feedwater pump will not be evenly split to the two steam generators. The flow from the motor driven emergency feedwater pumps will also vary depending on the steam generator pressure, but there is no interaction since each pump is dedicated to one steam generator.

The turbine driven emergency feedwater pump automatically trips and isolates on low steam generator pressure. The setpoint is P = 550 psig.

All three emergency feedwater pumps are also started for ATWS mitigation by the AMSAC circuit on loss of both main feedwater pumps.

The turbine driven emergency feedwater pump trips automatically when steam generator level 96% on the operating range. The motor driven emergency feedwater pumps do not trip automatically, but have to be stopped manually by the operator. Manual (not automatic) isolation of motor driven emergency feedwater occurs following steam generator depressurization or steam generator overfeed. An automatic emergency feedwater isolation system is currently being designed and will be installed beyond 1999. This future plant modification will reduce the reliance on manual operator actions.

In our RELAP model, we consistently get a trip of the main feedwater pumps because of high discharge pressure, following a reactor trip. The emergency feedwater pumps are modeled separately in RELAP by time dependent volumes and time dependent junctions to control steam generator levels to applicable set points. The only occasion it made difference is when turbine driven pumps are tripped on low steam generator pressures. We modeled them to be tripped in RELAP5 for the overfeed transients when the operator is supposed to trip them. At what conditions they are stopped depend on the transient and assumptions we make. The two overfeed case REALP5 has run so far tripped emergency feedwater when steam generator levels reached (1) 96% operating range and (2) the top of steam generators. In the first case we just terminated emergency feedwater flow from then on, but in the second case we continue the emergency feedwater feed to maintain the level at the top of steam generators

Steam Generator Level Control

The nominal amount (mass) of liquid in the steam generator during normal operation at full power is 16,050 kg (35,300 lb) for a conservatively low value. The actual plant value is not known, but it is probably in the range of 35,300‑40,000 lb. This does not include the steam vapor mass. For a conservatively high value, one could allow the steam generator downcomer to be full of saturated liquid. During normal operation, the current Oconee input deck calculated steam generator inventory to be about 40,000 lbs.

The startup range level taps are at 6 inches and 394 inches above the upper surface of the lower tube sheet (AUSLTS). The operate range level taps are at 102 inches and 394 inches AUSLTS. The high steam generator level trip set point for main feedwater at 96% of the operating range in either steam generator.

From zero to approximately 15% power, the steam generator level is controlled by the ICS to the minimum level setpoint of 25 inches on the startup range (31" above the upper surface of the lower tube sheet). At power levels above 15% there is no level setpoint, rather, the level is a result of the ICS control of main feedwater flow to match the reactor power. At full power the indicated level is around 60‑65% of operating range (277"), but this varies by unit and steam generator due to tube plugging, crud, etc.

Reactor Tripped and any Reactor Coolant Pumps on

Level control by main feedwater is 25" on the startup range (31" AUSLTS)

Level control by emergency feedwater is 30" startup range (36" AUSLTS).

Reactor Tripped and Reactor Coolant Pumps off (natural circulation)

Level control by main feedwater is 50% operating range (correction from the IPTS study value of 60%) (248" AUSLTS)

Level control by emergency feedwater is 240" startup range (246" AUSLTS).

Given a equal level demand signal from both generators, will feedwater feed both generators at the same rate (post‑trip)? (e.g if one generator should be at a lower pressure than the other but with both levels the same, will the feedwater flow be equal?). The post‑trip feedwater demand for each SG with be whatever it takes to maintain the level setpoint. There can be different post‑trip steam loads on each steam generator, so the feedwater flow rates can be different, but they should be relatively similar.

Steam Generator Pressure Control

The secondary side pressure during normal operation is 6.38 MPa (925 psia). There are no main steam isolation valves. There is no flow limiting venturi in the current SGs. There will be one in the replacement steam generators.

Secondary side pressure control is effected by the turbine stop and flow control valves, the turbine bypass valves, and the secondary steam relief valves. The secondary side pressure can be categorized into three states:

Steam line pressure greater than 1050 psi, which causes a demand signal for steam relief valves and steam dump valves;
Steam line pressure between 935 psi and 1050 psi, which causes a demand signal for steam dump valves only; and
Pressure less than 935 psi, which causes no demand signal.

Upon a turbine trip signal, the turbine stop valves will close. Main feedwater is run back by closing down the main feedwater flow control valves, reducing the main feedwater pump speed, and throttling the auxiliary feedwater flow control valves. The steam dump valves will open and several steam safety/relief valves may open to maintain steam generator pressure at 6.97 MPa (1010 psi). Primary system temperature drops to 560K (549F). Shrinkage of the liquid in the primary system can lead to loss of pressurizer water level and tripping of the pressurizer heaters.

Steam Generator Safety Valves

Each steam line has four pairs of safety/relief valves, for a total of sixteen, that vent to atmosphere. The valves open in four stages, with set points that range from 7.24 MPa (1050 psi) to 7.61 MPa (1104 psi). The total capacity is 114% of full power. All sixteen valves are expected to lift following a turbine trip from full power.

The throat area of safety valves is 16 in² . Flow rates were confirmed in calculations. The design flow rate, based on a lift set point of 1050 psig, is 220 lbm/sec. The nominal, or best-estimate, flow rate is 244 lbm/sec. Flow rates were confirmed in calculations. The set point are:

One valve at 1050 psig

One valve at 1065 psig

One valve at 1080 psig

One valve at 1090 psig

Two valves at 1100 psig

Two valves at 1104 psig

A blowdown of 8% for was used for the reseat pressure, e.g., if the set point is 100 psig, that valve will reseat when the pressure drops to 92 psig, after opening at 100 psig.

Each steam line also has a manually actuated atmospheric dump valve which is normally not operated.

The original RELAP5 model used only 4 safety valve set points. The 8 valves on each loop use 6 different set points. These were all incorporated into the current RELAP model. A RELAP5 valve component is used in each loop to model 8 valves. Control logic is used to determine (based on the pressure in the steam line) how many valves should be open. If one valve is open, the RELAP5 valve component is opened to 1/8th of its total flow area. If two valves are open, the valve component is opened to 1/4th of its total flow area.

To check the flow rate through the valves, a small test model was developed where a time dependent volume maintained the upstream pressure at 1050 psig (just at the valve opening set point). The resulting flow through the safety valve was 245.5 lbm/sec (slightly above the Oconee nominal flow rate of 244 lbm/sec). The design flow (220 lbm/sec) is the minimum allowed flow at the given pressure (1050 psig). The nominal flow (244 lbm/sec) is that which is actually expected. The RELAP5 results are in very good agreement with the nominal flow value.

Turbine Bypass Valves

Two pairs of turbine bypass valves, one pair per steam line, permit steam to be dumped directly to the condenser. The turbine bypass valves have a total capacity of 25% of full power main steam flow. The turbine bypass are designed to control steam generator pressure to 6.21 MPa (885 psig) during normal operation, and 7.07 MPa (1010 psig) following reactor trip. The turbine bypass valves actuate if the turbine header pressure exceeds its set point by 0.34 MPa (50 psi) under normal operating conditions.

Following a turbine trip/reactor scram, the valves lift at 0.86 MPa (125 psi) above the turbine header pressure set point, corresponding to lifting and controlling at 1010 psig.

The turbine bypass valve in the RELAP5 model works on a PI controller to maintain pressure at the given set point. The valve is not necessarily closed at the set point pressure.

There is manual isolation of turbine bypass valves in the plant in the event of failures

Turbine Stop Valves

There are four turbine stop valves, two on each steam line, linked to a common header upstream of four governor valves. Closure of turbine stop valves on one steam line isolates that steam generator from the other, for example, in the event of a main steam line break. A turbine trip generates a reactor trip.

Primary system

Reactor Trips

A low pressure reactor trip signal is generated at 12.52 MPa (1800 psig) while HPI starts at 10.45 MPa (1500 psig; since changed to 11.07 MPa, 1590 psig). At the time of the IPTS study, operator procedures required the operator to trip all four reactor coolant pumps upon actuation of HPI. It has since been changed to loss of subcooling. The high temperature reactor trip is at 618F.

The variable P‑T trip is bounded by the low pressure trip at 1800 psig, and by the high temperature trip at 618F. The reactor will trip when the actual pressure is less than the set point pressure "P" in the above equation for a given value of T‑hot. For example, for T‑hot = 605F, the pressure set point is 2034 psig. If the plant pressure is less than 2034 psig, the RPS will trip the reactor for a temperature of 605F. The variable low pressure reactor trip (DNB) is calculated by

P (psig) = (11.14 x T_hot (F)) - 4706

The low pressure trip, high temperature trip and variable P/T trip are all included in the RELAP5 model.

High Pressure Injection

High pressure injection consists of three motor driven centrifugal pumps, one of which is in use during normal operation for makeup as part of the Chemical and Volume Control System (CVCS). The makeup flow will be automatically shut off when HPI started. All three pumps start on a safety injection signal and draw from the refueling water storage tank. The pumps connect to a header system to deliver flow to all four cold legs. The HPI actuation pressure decreases to 10.45 MPa (1500 psig). Since the IPTS study, the set point was increased to 11.07 MPa (1590 psig). Approximately two-thirds of the HPI flow enters loop A while the remainder enters loop B. After an actuation, HPI remains on until it is manually shut off.

Nominal HPI flow vs. reactor coolant system pressure (at the injection line connections) for all three HPI pumps operating. This is what we would expect on an engineered safeguards actuation. This will include the line losses, which you can't get if you try to use the FSAR pump curve. Normally, the A and B HPI pumps are injecting through the A1 and A2 cold legs, and the C HPI pump is injecting into the B1 and B2 cold legs. There are also cross connect valves that the EOP opens to address certain pump and valve failures. Note that the emergency operating procedure directs the operators to throttle HPI given certain conditions, and these are for unthrottled flows.

Table 7-3

High Pressure Injection Flow (gpm)

Reactor Coolant System Pressure (psig)	A1	A2	B1	B2	Total
100	391	396	265	272	1324
300	376	381	255	261	1273
600	352	357	239	245	1193
900	328	332	223	228	1111
1200	301	305	205	210	1021
1500	272	275	186	190	923
1800	240	243	165	169	817
2170	194	196	135	138	663
2500	142	144	102	104	492
2800	74	75	59	61	269

The HPI is capable of repressurizing the primary system to the safety valve set point.

In Oconee (typical B&W) the HPI enters through a 2 1/8 inch line. At 1000 gpm injection rate (the flow rate at 1000 psi primary system pressure) the injection velocity is 7 m/s (22 ft/s).

I would guess the velocity for CE and W must be more like about 0.5 m/s.

It is up to the operator to throttle HPI to control either the pressurizer level, or the subcooled margin, depending on the transient. The procedures require the operator to throttle HPI to limit the subcooled margin. At the time of the IPTS study, operating procedure specified that the operator throttle the makeup system on attainment of 28K (50F) subcooling. Currently, the operator is permitted (not required) to throttle HPI when the subcooled margin is greater than 5F (and, normally when pressurizer level is >80 inches). The HPI flow should be stopped when pressurizer level > 480 " (pressurizer height = 43.26') , when the high level alarm actuates.

The operator is permitted (not required) to throttle HPI when the subcooled margin is greater than 5F. When it is possible to establish subcooling, the operator must throttle HPI to limit subcooling and to stay within the Thermal Shock Operating Region. When doing so, it is desirable, but not required, to maintain pressurizer level >80 inches so that the heaters can be used to assist in controlling pressure.

The operator is required to throttle HPI as necessary to decrease and maintain pressure within the Thermal Shock Operating Region if the pressurized thermal shock criteria are met. The pressurized thermal shock criteria are:

all reactor coolant pumps off, AND T_c <500F, AND HPI has actuated in the ES mode,

the cool down rate has exceeded 50F per 1/2 hour, AND a 100F temperature decrease has occurred.

The Thermal Shock Operating Region upper pressure limit corresponds to a 100F subcooled margin.

For the loss of all feedwater scenario in which feed‑and‑bleed cooling has been aligned, the operator is required to allow sufficient HPI flow to maintain core exit thermocouple temperatures decreasing, even if this results in exceeding the Thermal Shock Operating Region upper pressure limit. This is based on giving core cooling precedent over pressurized thermal shock mitigation.

HPI is modeled in RELAP by time dependent volume and time dependent junction. The temperature of the HPI water source is assumed to be 70F. For the stuck-open TBV case, HPI is throttled to maintain the pressurizer level at 220".

Core Flood Tanks (Accumulators)

There are two accumulators, with a total liquid volume of 59 m³. The accumulators are pressurizer to 4.24 MPa (600 psig). The two accumulators inject, 180 degrees apart directly into the reactor vessel two feet above the plane of the loop nozzles.

Low Pressure Injection

The low pressure injection pumps start when pressure decreases to 3.45 MPa (500 psi). Their shutoff head, however, is 1.38 MPa (200 psi), so there is no actual injection until this time. At 100 psi the injection rate is 379 kg/s.

The LPI water temperature assumed in the current RELAP calculations is 70 F.

Reactor Vessel and Reactor Vessel Vent Valves

The Oconee reactor vessel has a stainless steel cladding 0.22 inches thick. The vessel wall is 11.45 inches thick from the loop nozzles to the upper circumferential weld. Below this the thickness reduces to 9.64 inches.

There are eight vent valves connecting the upper plenum to the downcomer. The vent valves begin to open at a differential pressure of 0.85 kPa (0.125 psi) and are fully open at a differential pressure of 1.79 kPa (0.26 psi). The vent valves can open during a PTS event to allow warm water or steam to flow from the upper plenum to the upper part of the downcomer. If the downcomer temperature were 149C (300F) the vent valves would begin to open when the core temperature was 159C (318F) and would be fully open at a core temperature of 169C (336F)

The downcomer and accumulator tee are divided into six sectors connected by cross-flow junctions. Related heat structures are also divided into 6 sectors where necessary. The 8 vent valves are simulated by 6 valve junctions each connected to one of the 6 sectors. The downcomer is divided into 5 axial volumes.

The upper head should not be stagnant. Two connections should be made to allow circulation. This question was raised by Duke Power. There is a connection through the brazements (guidetubes) in addition to the connection between the top of the upper plenum and the upper head. The flow area between the top of the upper plenum and the upper head is 32.4 ft². From drawings given in the Oconee calculation notebook, the flowpath between the upper plenum and the upper head is as indicated in the noding diagram. The drawings do not show any flowpaths to the downcomer or other vessel regions. The author of the calculation notebook (C.D. Fletcher) noted that the upper plenum nodalization layout agrees with the unique design of the B&W annular upper plenum.

We could split the flowpath into two parts if Duke Power is concerned about circulation to/from the upper head region. This change may affect results generated to date and would require regeneration of results in the report. If we make this change, it would help if we had drawings of the Oconee vessel that show the geometry of the upper plenum.

Pressurizer

During normal operation the pressurizer contains 19.8 m³ of saturated liquid and 22.7 m³ of saturated steam. The level set point for normal operation is to 220".

The pressurizer heaters have a maximum capacity of 1.64 MW. The pressurizer has one power operated relief valve (PORV) which has an equivalent diameter of 2.8 cm. The PORV is set to open at 16.9 MPa (2450 psia) and close at 16.6 MPa (2407 pisa). The pressurizer also has two safety valves which have an equivalent diameter of 4.6 cm (1.8 in). They are set to open at 17.2 MPa (2500 psi). The two safety valves have a combined design flow capacity of 84 kg/s.

Pressurizer Level Control

The normal level is 220". Makeup and letdown flow control pressurizer level to be 220 inches. To maintain pressurizer level, the operator will normally start a second pump during a transient that involves shrinkage of the primary system liquid volume. The IPTS study did not model the startup of a second pump. The makeup flow is automatically shut off when HPI is started. Letdown flow is isolated when pressurizer P 1600 psig. The makeup flow is automatically shut off when HPI started. Afterward it is up to the operator to throttle HPI to control either the pressurizer level, or the subcooled margin, depending on the transient.

The pressurizer level high annunciator alarms at 260 inches.

Pressurizer Pressure Control

Manual reactor coolant system depressurization to limit the subcooled margin. Operator guidance to promptly reduce reactor coolant system pressure following overcooling transients and small break LOCAs. Operator procedures to limit the repressurization of the reactor coolant system, as directed by the Oconee emergency operating procedures

Pressurizer heaters come on automatically when the level is restored in the RELAP5 model.

Power Operated Relief Valves

We have the FSAR section that describes the PORV, but that simply states its capacity as 107,000 lb/hr at 2450 psig. We ran the Oconee PORV capacity parameters (107,000 lb/hr at 2450 psig) through the RELAP critical flow model and produced an equivalent inside diameter of 0.96 inches. Is this consistent with your information?

The PORV has an orifice diameter is 1-3/32 inches. The rated flow (conservative low flow) per Dresser is 100,000 lbm/hr at 2300 psig. For best‑estimate analyses we use actual EPRI test data for our valve. The test data flowrate is 37 lbm/sec for steam conditions of 2318 psia and 658F. This information is for steam flow only. For liquid flow different modeling is required, since the test data show that the flowrate is a function of subcooling.

We re‑ran the PORV flow rate (i.e., 37 lbm/sec for steam conditions of 2318 psia and 658F) through the RELAP critical flow model and produced an effective inside diameter of 1.109 inches (1-3/32).

Safety Valves

Reactor Coolant Pumps

Each of the reactor coolant pumps has a rated power of 6.7MW for a total heat input to the primary system approaching 26.8MW. The pump flywheel inertia is sufficient to extend coast down to 100s. Tripping and restarting the reactor coolant pumps are manual operator actions.

Procedures in 1999 require tripping the pumps on loss of the subcooled margin (at the time of the IPTS study, the operator tripped the reactor coolant pumps on HPI actuation). The operator must trip the reactor coolant pumps when the subcooled margin decreases to zero. In the current RELAP calculations, the reactor coolant pumps are tripped when the subcooled margin is reduced to 0.5F, unless otherwise indicated. RELAP5 has a built-in model of reactor coolant pump coast down characteristics based on a Westinghouse reactor coolant pump.

Option 41 in the RELAP5 code is elected which will automatically dissipate reactor coolant pump power in the primary system.

Manual restart of reactor coolant pumps for thermal mixing. Early reactor coolant pump restart is no longer supported by operator response times.

Break

Flow energy loss coefficients are scaled from AP600 1" cold leg break case. These coefficients (forward and backward) are then scaled inversely proportional to the square of the area ratio. E. g., for 2" break, the loss coefficients will be 16 times smaller. The loss coefficients used were based on those determined for AP600. The discharge coefficient (CD) is set to 0.92 and the thermal nonequilibrium constant (Cne) is set to 3.5. These values are given in the latest version (gamma) of the RELAP5 manual (Volume IV, Models and Correlations, Section 7.3.5.1). As for the for loss coefficient, they are calculated as 1.12 * Area ratio squared (again, the 1.12 is from the RELAP5 manual). The area of the surge line pipe (where the break is located) is 0.4176 ft2. The area of a 1" break is 0.005454 ft2. This results in an area ratio of 76.568. So, the loss coefficient is 6566. For the 2" break case, the break area is 0.012272 ft2, resulting in a loss coefficient of 410.4. Other break coefficients are calculated in the same manner.

Subcooling

There are two temperature instrument sensor locations that are used to calculate and indicate the subcooled margin. These are the core exit thermocouples and the hot leg RTDs in both loops. The pressure instrument used is hot leg pressure, which is located on the vertical section of the hot legs approximately two feet below the start of the U‑bend. Subcooling margin is calculated conservatively by taking the highest of loop temperatures (hot or cold leg) in combination with the lowest reactor coolant system pressure input.

The indicated subcooled margin used by the operator has a built in error adjustment. When the indication reads zero degrees of subcooled margin, the sensor remains subcooled by an amount that is equal to the subcooled margin uncertainty.

When the reactor coolant pumps are off the core exit thermocouples are used.

Cooldown Criteria and Mitigation for Pressurized Thermal Shock

Criteria for pressurized thermal shock conditions are:

Cooldown rate has exceeded 100F/hr AND a cooldown of >100F has occurred, or
All RCPs are off AND any cold leg temperature is <500F AND HIGH PRESSURE INJECTION (HPI) has operated in the emergency injection (high flow rate) alignment.

Actual cooldown rate is calculated as follows; reactor coolant system cold leg temperature (T_CL) is used when any reactor coolant pump is operating. This temperature is measured by thermocouples in each of the four cold leg loop seals near the pump suction. Core exit thermocouples are used when all reactor coolant pumps are off. Cooldown rate is monitored utilizing cold leg temperature indication in the control room panels, and using cold leg temperature indication and core exit temperature indication on the operator aid computer (OAC). Cooldown rate can be calculated manually by the operator or automatically by the OAC. The OAC has a display group that lists all of the T_CL indication with per minute rates. The OAC also contains a dedicated (heat up and) cool down program that calculates T_CL and core exit temperature cool down rates every 1minute, 5 minutes and 60 minutes, i.e., there is a one minute interval (average) display, 5 minute interval display, and 60 minute interval display.

There is no set frequency that operators manually calculate cooldown rates, but I would think once every 5 minutes would be typical. The Tc indications come from thermocouples located in each of the four cold legs and the core exit thermocouples are located on top of the fuel assemblies.

Should the 100F/hr cooldown rate be exceeded with a subcooled reactor coolant system, the operator would decrease the steaming rate through the turbine bypass valves or the atmospheric dump valves to bring the cooldown rate back within the normal limit, if possible. For small break LOCAs the cooldown rate may not be controllable due to break cooling. Should the 100F/hr cooldown rate be exceeded with a saturated reactor coolant system, i.e., during a small break LOCA, the operator cannot throttle HPI until > 5F subcooling margin has been established.

When it is possible to establish subcooling, the operator must throttle HPI to limit subcooling and to stay within the Thermal Shock Operating Region. When doing so, it is desirable, but not required, to maintain pressurizer level >80 inches so that the heaters can be used to assist in controlling pressure.

The following design and procedure features are the main PTS-mitigation strategies for Oconee.

Automatic main feedwater isolation and automatic turbine-driven emergency feedwater pump trip on low steam line pressure (550 psig) to prevent continued main feedwater to a broken steam generator.
Automatic main feedwater pump trip on high SG level (96% OR)
Manual isolation of turbine bypass valve failures
Manual isolation of main and emergency feedwater following steam generator depressurization
Manual isolation of main and emergency feedwater following steam generator overfeed
Manual throttling of high pressure injection to limit the subcooled margin
Manual reactor coolant system depressurization to limit the subcooled margin
Manual restart of reactor coolant pumps for thermal mixing

Items 1 and 3 are new hardware that has been added since the 1986 NRC study. The reliance on manual operator actions and the magnitude of overcooling events driven by excessive primary-to-secondary heat transfer is significantly lessened by these design features. The remaining items have been in place in the plant design and procedures since 1985 (or earlier) when the upgraded emergency operating procedures per the TMI Action Plan were implemented. The operator response time for Item 9 has been determined to be significantly slower than was assumed in the 1986 NRC Oconee pressurized thermal shock study. In addition, an automatic emergency feedwater isolation system is currently being designed and will be installed beyond 1999. This future plant modification will reduce the reliance on manual operator actions, and will reduce the magnitude of overcooling transients and pressurized thermal shock risk.

RELAP Model

There were two volumes of the input calculation notebook produced while developing the initial Oconee‑1 input deck. The second volume describes modeling of the control system. We only have the volume on the thermal hydraulics. We do not have the Oconee notebook from 1985 that covered the control systems. Mike Waterman developed the control systems models. Mike's approach was to document each control block within the model, linking it back to detailed ICS schematics that he had at the time. The main part of the documentation was in the input model itself (80%), while the remainder was in supporting notes and schematics (20%).

From his description of the control system model documentation in the deck compared to what we have, it appears that much of the documentation originally in the model was removed by someone after Mike was involved. Mike stated that the line count in the original model was about 20,000 lines (compared to about 9000 lines in the current model.

Mike thought that Cliff Davis of INEEL may also provide some information on the early development of the Oconee model as he was involved with some model development and debugging. Another source may be Chuck Dobbe.

The control system in this deck is very complicated. This can be expected in decks that have undergone decades of evolution. In this case, the issue is compounded in that a large number of NPA control cards are interspersed and that the numbering of some volumes and the noding has been altered from what is indicated in the schematic. The evolutionary nature of the deck is illustrated by the fact that though it uses British units, some of the pressure related control tables are in SI.

For the objective of Oconee PTS studies, we need to model only a small part of the complicated B&W ICS. Except the MSLB circuitry that still needs to be verified for its existence and function and the level control when emergency feedwater is in operation, most of the necessary control function appeared to have been modeled in the existing Oconee‑1 RELAP5 input deck.

NRR had INEL update the RELAP Oconee‑1 model to MOD3 in the 1993-95 time frame and the deck was tested to run a steady state. John Burtt managed that effort. The input was put on the data bank in the location: <http://res21/cgi‑bin/databank3.pl> Previously, around 1990, Scott Ghan modified the 1985 Oconee‑1 deck when they did the small break CSAU study. There were also modifications made to the steam generator model in conjunction with the MIST program; and modifications associated with NPA.

The vessel was modeled with 8 axial levels and 6 azimuthal sectors. The downcomer annulus is divided into six circumferential sectors connected by cross-flow junctions. Related heat structures are also divided into six sectors where necessary. The eight vent valves are simulated by six valve junctions each connected to one of the six sectors

The downcomer is divided into five axial elevations.

All major components of the secondary system were modeled. The steam generator secondary was changed to use the vertical bundle with cross flow heat transfer method. The turbine driven and motor driven emergency feedwater are modeled separately in RELAP5 using different time dependent volumes and time dependent junctions to control steam generator levels to applicable set points. The only occasion it made a difference is when turbine driven pumps are tripped on low steam generator pressures. The emergency feedwater pumps are modeled in RELAP5 to trip for the overfeed transients when the operator is supposed to trip them, unless otherwise indicated.

The HPI is modeled by four time-dependent volume and a time-dependent junctions that inject through side nozzles of the cold legs. The nozzles are located at an elevation somewhat higher than the centerline of the cold/hot legs. The temperature of the HPI water source is assumed to be 90F. For the stuck-open TBV case, HPI is throttled to maintain the pressurizer level at 220".

At what conditions the emergency feedwater is stopped depend on the transient and assumptions. The two overfeed case RELAP5 has run so far tripped emergency feedwater when steam generator levels reached: (1) 96% operating range; and (2) the top of steam generators. In the first case we just terminated emergency feedwater flow from then on, but in the second case we continue the emergency feedwater to maintain the level at the top of steam generators. While the emergency feedwater pumps can only be stopped manually, emergency feedwater flow is controlled to maintain a given level in the steam generators.

Review of NUREG/CR-3770

The following comments identify items related to Pressurized thermal shock that are not correct for Oconee in 1999. The level of significance of the benefit or penalty is stated.

xvi: The report states that SLB transients are most important for pressurized thermal shock and that operator action to isolate the SG is the most important operator action. Based on the 1999 design having added an automatic main feedwater isolation system, these statements may no longer be correct.
pp. 2.11 & 2.39: The HPI actuation setpoint has been increased from 1500 to 1590 psig. This is judged to not be a significant change for pressurized thermal shock.
pp. 2.18 & 2.42: The report states that no automatic feedwater isolation exists. This is no longer true based on the 1999 design. This is a significant benefit for pressurized thermal shock if revised.
P. 2.20: The steam generator level for natural circulation is 50% OR, not 60%. This is not a change, only a correction.
p. 2.20: The EFW pumps no longer start on main feedwater pump discharge pressure <750 psig with the 1999 design. The pumps do start on low steam generator level. This is judged to not be a significant change for pressurized thermal shock.
pp. 2.20 & 2.42: The turbine-driven emergency feedwater pump is now automatically stopped on low steam line pressure. This is a significant benefit for pressurized thermal shock if revised.
p. 2.22: The report states that the protection system trips the main feedwater pumps when level reaches 90%. This is not correct in that the Integrated Control System (ICS) trips the pumps and the correct setpoint is 96%. This is not a change, only a correction.
p. 2.23: The 1999 design incorporates a replacement digital ICS, which is superior to the previous ICS in terms of being less likely to initiate or aggravate an overcooling transient, and more likely to automatically mitigate an overcooling transient. The digital ICS is more robust in terms of surviving failures in inputs, etc. The entire ICS section of the report would need to be replaced to be correct. This is judged to be a moderate benefit for pressurized thermal shock if revised.
p. 2.32: In the 1999 design, the turbine-driven EFW pump is automatically isolated following an overcooling event that results in low SG pressure. This is judged to be a significant benefit for pressurized thermal shock if revised.
p. 2.38: The report states that several of the steam safety relief valves may open after a turbine trip. There are sixteen valves, and normally all will open following a turbine trip from full power. This is a correction that is judged to have a minor penalty for pressurized thermal shock if revised.
p. 2.39: The report states that the operator will throttle HPI when a 50F subcooled margin exists. Procedures in 1999 allow throttling once a 0F subcooled margin exists. This is judged to have a minor benefit for pressurized thermal shock if revised.
p. 2.39 & 2.42: The report states that the operator will trip the reactor coolant pumps on HPI actuation. Procedures in 1999 require tripping the pumps on loss of the subcooled margin. This change is judged to have no impact for pressurized thermal shock.
p. 2.39: The discussion in Section 2.3.2 does not acknowledge that the procedures require the operator to throttle HPI to limit the subcooled margin. This is the key small break LOCA pressurized thermal shock-related operator action. This is judged to be a significant benefit for pressurized thermal shock if revised.
p. 4.3, Table 4.1: Transients 2 and 5 assume early RCP restart, which is no longer supported by operator response times. This is a significant penalty for pressurized thermal shock if revised.
p. 4.4 , Table 4.2: Transients 4 and 5 assume early RCP restart, which is no longer supported by operator response times. This is a significant penalty for pressurized thermal shock if revised.
p. 4.5: The extrapolation of the TRAC and RELAP5 analyses directly and by using a simple energy balance model is mentioned. This approach was necessary due to high mainframe computing costs which would no longer be applicable today. These extrapolations are extremely conservative in some cases, and even non-physical or unrealistic in other cases (e.g. temperatures much less than 200F and inconsistent with the scenario and/or reasonable credit for operator action to eventually mitigate an event lasting for hours). Refer to Figures 4.43 and 4.48 for examples of non-physical or unrealistic extrapolated temperature predictions. This is judged to be a significant benefit for pressurized thermal shock if revised.
p. 4.9: The RELAP5 vessel upper head modeling (stagnant upper head model) is not appropriate for the known vessel flow distribution. This is judged to be a small penalty for pressurized thermal shock if revised.
p. 4.10: The RELAP5 reactor vessel downcomer is modeled with a single volume. This model artificially mixes the entering flow from the two loops. This is judged to be a small penalty for pressurized thermal shock if revised.
p. 4.20: The TRAC reactor vessel model has limitations in the upper head representation as stated in the report. This is judged to be a small penalty for pressurized thermal shock if revised.
p. 4.27: The TRAC modeling of the EFW System does not represent the actual plant design at all. This is judged to be a significant benefit for pressurized thermal shock if revised.
p. 4.27: The document states that for a normal reactor/turbine trip transient the steam relief from the turbine bypass valves is adequate so that modeling the main steam safety valves is not necessary. This statement is incorrect based on operating experience. The basis for this statement may bring into question the accuracy of the TRAC model, or it could simply be incorrect text. This is judged to be a correction only.
p. 4.29, Table 4.4: The RELAP5 original steam line break analysis has no HPI throttling. This results in the reactor coolant system pressure remaining at 2500 psig for two hours, which is unrealistic. This is judged to be a significant benefit for pressurized thermal shock is corrected.
p. 4.30 and other sections of Chapter 4: Both the RELAP5 and the TRAC simulations assume that the reactor coolant system is allowed to heat up following overcooling transients that are successfully mitigated. Assuming that overcooling events are not successfully mitigated (i.e. the cooldown continues and full repressurization occurs) for a two hour scenario is unrealistic. These are judged to be significant benefits for Pressurized thermal shock if corrected.
p. 4.40: The RELAP5 revised main steam line break discussion points out that RCP restart is a significant action, which is correct. This is judged to be a significant penalty for pressurized thermal shock if corrected.
p. 4.44, Section 4.3.1.6: The results of the turbine bypass valve failure at reactor hot standby appear to be much too rapid of a cooldown based on Duke analysis experience. There is insufficient information to identify why the results are as stated. This is judged to be a significant benefit to pressurized thermal shock if corrected. I previously sent Bill Galyean a copy of the 1981 Duke PTS report, which has our old analyses in it.
p. 4.107, Section 4.5: The section Extrapolated Sequences describes a very approximate and overly conservative method for extrapolating the thermal-hydraulic analyses out in time due to limited computer resources in the 1986 study. This type of compromise in technical accuracy would not occur with todays workstation computer power and cost. This methodology is judged to be a significant benefit for pressurized thermal shock if reanalyzed explicitly with the computer code model.

Summary

The review of the 1986 NRC Oconee pressurized thermal shock study relative to the 1999 plant design has identified one significant non-conservatism in the 1986 analyses. That non-conservatism is the assumption that the operators will restart the RCPs in a rather short period of time and restore forced circulation and thermal mixing. As stated in NUREG/CR-3770, restarting the RCPs is a significant benefit in that the water temperature incident on the reactor vessel welds will increase. Recent emergency operating procedure validation studies conducted at Oconee indicate that this action will not occur as early as credited in the analyses.

The review also identified several significant conservatisms in the 1986 analyses relative to the 1999 design, as follows:

The plant design has been modified since 1986 to incorporate a MFW isolation system which also isolates flow from the turbine-driven EFW pump on low steam generator pressure. This new capability significantly improves the reliability and timing of MFW and EFW isolation, which previously relied on manual operator action only.
Upgraded emergency operating procedures at Oconee include pressurized thermal shock mitigation and recovery actions which were not all credited in the 1986 analyses. These include manual actions to mitigate all causes of overcooling events, and specific guidance to promptly reduce reactor coolant system pressure following overcooling transients and small break LOCAs. Allowing the reactor coolant system to fully repressurize in the 1986 study is grossly conservative and invalid based on current operating practices. This is particularly true in that the analysis assumes no operator response to reduce reactor coolant system pressure for a two hour period.
The extrapolation methods used to extend the thermal-hydraulic analysis results out to two hours in the 1986 study are extremely conservative, as stated in the report. Some extrapolation method was necessary due to use of mainframe computers and the associated high cost at that time. Extending the analyses, rather than using the simplistic extrapolation methods, would result in higher coolant temperatures and less pressurized thermal shock risk. Using conservative thermal-hydraulic methods is not consistent with the application of probabilistic methods to obtain a meaningful evaluation of pressurized thermal shock risk.
The plant design will be modified in the next several years to include an automatic emergency feedwater isolation system. The purpose of this system is to remove the manual burden of isolating emergency feedwater to a steam generator that is causing an overcooling event. Once installed this system will significantly improve the reliability and effectiveness of the overcooling transient mitigation strategy.

Conclusions

The plant design changes since 1986 (existing main feedwater isolation and planned emergency feedwater isolation systems) will significantly lessen the magnitude of overcooling transients as well as reduce the reliance on the operator. These design changes are directly applicable to the most significant pressurized thermal shock transients, which are steam line breaks and turbine bypass system failures. Consequently, the magnitude of many overcooling transients will be less than what was concluded in the 1986 NRC Oconee pressurized thermal shock study. In addition, including some realistic credit for operator action to limit the repressurization of the reactor coolant system, as directed by the Oconee emergency operating procedures will substantially lessen the pressurized thermal shock risk. These two improvements in plant design and operation will more than offset the effect of a later restart of the reactor coolant pumps, mainly because the magnitude of the cooldown and repressurization will be less, and therefore there will be less need for reactor coolant pump restart to provide thermal mixing and mitigate the cooldown of the reactor vessel.

Should the integral effect of these changes in the plant design and operator response need to be quantified by reanalysis, todays computer power will enable elimination of the conservative extrapolation method employed in the 1986 study. Reanalysis would be expected to significantly improve the temperature responses, and lessen the pressurized thermal shock risk. Reanalysis should not be necessary unless the improvements in the fracture mechanics area do not provide the needed margin to support the intended life extension and associated increase in fluence that is predicted for Oconee. However, if reanalysis is to be undertaken, then the additional comments related to the inaccuracies in the RELAP5 and TRAC models can also be corrected prior to use.

Table 7-4

Oconee-1 Set Points

Accumulator pressure	600 psig
Low pressure injection head	200 psig
High pressure injection actuation	1500 psig
T_av at power	577K (579F)
T_av at zero power	560K (549F)
Auxiliary feedwater start signal	low sg level
SG high level limit	8.14 m (344 in)
SG low level limit	0.64 m (25 in)	RCPs operating
SG low level limit	6.1 m (240 in)	RCPs tripped
Secondary side pressure Secondary side temperature	6.86 MPa (1010 psig) 556K (542F)	hot standby
Secondary side pressure	6.28 MPa (925 psi)	100% power
PORV opening setpoint	2450 psig
Low pressure trip	12.41 MPa (1800 psig)

7. Review of IPTS Study Calculated Results

7.1 Oconee-1

7.1.1 Introduction

On page xv of the Oconee report (NUREG-3770) the first objective of the PTS evaluation was to provide a best estimate of the probability of a through-the-wall crack occurring in the reactor pressure vessel as a result with PTS. The base case main steam line break that was analyzed, however, indicates that HPI is not throttled (p. 4.28). More typically HPI is never throttled during the transients.

For what node in RELAP is the minimum downcomer fluid temperature reported?

The calculations were carried out by INEL using RELAP (Fletcher) and by LANL using TRAC (Ireland). The original objective was to run the calculations out to 8000s but this could not be achieved due to computer costs and stability difficulties with the codes. Consequently, only a limited number (20) of event sequences were calculated because of the computer costs. Of those, many were terminated prematurely, with the remainder of the transient being extrapolated in some manner, which may have been artificially conservative. The report states that the intention was to perform best-estimate analysis. ORNL identified the transients to by analyzed by TRAC or RELAP, or TRAC and RELAP, as shown in Table 4.3-2.

The IPTS study considered a 2.5 inch break in the RCP pump suction leg in the A1 loop. This break was intended to simulate a letdown line break.

Three pressurized thermal shock transients were calculated with both codes. These are cases # 2, 5, and 11 in the table. Two transients were calculated to be of possible risk significance. These were # 5 and 13. Number 5 was a 2-inch hot leg break, located in pressurizer surge line, was calculated with both TRAC and RELAP. Systems were assumed to operate as intended.

Number 13 was turbine bypass valves fail open (4/4) calculated with and without failure of steam generator level control, failure to restart reactor coolant pumps, and failure to throttle HPI. The accident was initiated from hot standby initial conditions. RELAP was used for the calculation.

The most severe transient analyzed with TRAC was the number 4 fromTable 4.3-2, stuck open turbine bypass valves

Most calculations were terminated well before the objective of 7200 s due to run time/cost considerations, and the calculated results were extrapolated to 7200 s. Further studies were recommended to evaluate a wider range of operator actions.

Table 7-2

IPTS Study

Oconee Transients Analyzed

	Transient	Description	Code
1	Turbine trip	Actual plant transient of March 14, 1980	TRAC, RELAP
2	Stuck open PORV	Failure to run back main feedwater; reactor coolant pump trip	TRAC, RELAP
3	Turbine bypass valves fail open (2/4)	w & w/o *failure of steam generator level control*, restart reactor coolant pumps, throttle HPI	*TRAC*
4	*Turbine bypass valves fail open (4/4)*	*w & w/o failure of steam generator level control, restart reactor coolant pumps, throttle HPI*	*TRAC*
5	2-inch hot leg break	In pressurizer surge line, reactor coolant pumps trip, systems operate as intended	TRAC, RELAP
6	4-inch hot leg break	In pressurizer surge line, reactor coolant pumps trip, systems operate as intended	TRAC
7	Rancho Seco	Loss of feedwater followed by steam generator overfeed.	TRAC
8	Steam generator overfeed	Failure of feedwater trip on high steam generator level. all other systems operate as intended	RELAP
9	Stuck open PORV	Failure to run back main feedwater; reactor coolant pumps do not trip	RELAP
10	Main steam line break (34")	Steam generators isolated at 10 min., intact steam generator refilled by 15 min, restart one reactor coolant pump per loop upon regaining 50F subcooling margin.	RELAP
11	Main steam line break (34")	Steam generators isolated at 10 min., HPI throttled, w & w/o *emergency feedwater*, w & w/o restart one reactor coolant pump per loop upon regaining 75F subcooling margin	TRAC, RELAP
12	Steam generator overfeed	Failure of feedwater trip on high steam generator level. All other systems operate as intended	RELAP
13	Turbine bypass valves fail open (4/4)	from hot standby, w & w/o failure of steam generator level control, restart reactor coolant pumps and throttle HPI, hot standby initial conditions	RELAP
14	2.5-inch cold leg break	Located in reactor coolant pump suction, all systems operate as intended	RELAP
15	Steam generator tube rupture	Broken steam generator isolated at 20 minutes	RELAP

The RELAP model included the main and auxiliary feedwater systems, turbine bypass, turbine stop valves, secondary side safety/relief valves. The model included 220 volumes, 232 junctions, and 208 heat structures. Loop A of the model contained the pressurizer. Each cold leg contained a HPI port. A single channel was used for the downcomer and the eight vent valves were combined and modeled as one. The low pressure injection and accumulators were included in the model.

The TRAC model utilized the 3-dimensional vessel nodalization, with eight axial levels, two radial rings and six azimuthal sectors. Of the eight axial levels, one constituted the lower plenum, four the core, two the upper plenum, and one the upper head. The core comprised the inner radial ring and the downcomer the outer. Two connections were added between the upper head and the hot legs to allow a flow path. The eight vent valves were grouped into six in the model.

The HPI flow was input as 283K (50F). The flow to loop A is higher than the flow to loop B, in keeping with the plant design. (What about RELAP?) The accumulators are included in the TRAC model, while the low pressure injection was not.

Contrary to RELAP, the secondary side safety/relief valves were not modeled. This appears to be inadequate since RELAP calculations show the safety relief valves lift (e.g see transient #6). The turbine stop valves and turbine bypass, however, were included.

For Oconee 10E-6 was chosen and anything below this was considered to be residual. This resulted in residuals being larger than the higher probability event. Therefore, 10E-7 was used for Calvert Cliffs and H.B. Robinson.

The study concluded that main steam line break was the most limiting event. The most important plant features which influenced the event were internal vent valves and feedwater pump trip on high steam generator levels. According to [4], isolation of feedwater is now an automatic action rather than an operator action.

7.2.2 Turbine trip (TRAC, RELAP)

TRAC

Results are not reported as the calculation was more of the nature of a benchmark.

RELAP

Results are not reported as the calculation was more of the nature of a benchmark.

7.2.3 Stuck open PORV (TRAC, RELAP)

TRAC

The calculation was run to 1000 s and extrapolated to 7200 s.

The transient initiates with the opening of the PORV at time 0. The reactor coolant pumps tripped 30 s after HPI initiation. Feedwater failed to run back so the steam generators filled until the high level trip signal was generated.

The primary system pressure was calculated to increase to 11.5 MPa (1668 psi) following HPI actuation. The TRAC-calculated heat transfer coefficient was approximately 1500 W/m²-K. The minimum downcomer temperature reached was 528K (491F). The scenario, therefore, was not risk significant.

RELAP

The calculation was run to 1000 s and extrapolated to 7000 s.

The transient initiates with the opening of the PORV at time 0. The reactor coolant pumps are not tripped, contrary to the TRAC calculation. The minimum pressure reached was 8.68 MPpa (1259 psia). HPI actuated but did not repressurize the primary system above 1800 psi. The pressure calculation is similar to TRAC. The heat transfer coefficient remained high at around 24,000 W/m2-K because the reactor coolant pumps were not tripped. The minimum downcomer fluid temperature calculated was 560K (549F) and the minimum extrapolated temperature was 545K (521F) at the end of the extrapolation. The scenario, therefore, was not risk significant.

7.2.4 Turbine bypass valves fail open (2/4) (TRAC)

The calculation was run to 1200 s and extrapolated to 7200 s

The event is initiated by a reactor trip and turbine trip. Both turbine bypass valves from one steam generator open and fail to close. Feedwater to the affected steam generator fails to run back. Level control for auxiliary feedwater flow to the affected steam generator fails. The operator does not restart the reactor coolant pumps. The operator does not throttle HPI.

Primary system pressure decreased to the HPI set point in about 150 s. Pressure then increased to the PORV set point as the HPI pumped the primary system water solid by 1000 s. Minimum downcomer temperature of 465K is reached at the end of the calculation (1200 s). The temperature is extrapolated to further decrease to 420K (300F) by 4000 s, and to 365K at 7200 s, at a rate of about 75K (135F) per hour. If the extrapolated temperatures are correct, this case could be pressurized thermal shock significant.

Two parametric variations were run. The first was for steam generator level control for auxiliary feedwater flow to the affected steam generator operated as intended. Pressure history was the same as the base case. Temperature at 1200 s was about 490K, some 25K higher than the base case. Extrapolated temperature never decreased to 420K. The minimum extrapolated temperature was 450K at 7200 s. This parametric variation, therefore, was not risk significant.

The second parametric variation additionally included operator actions to restart the reactor coolant pumps and throttle HPI. Throttling HPI prevented repressurization. Instead, primary system pressure continued to decline. Pressure was about 6.5 MPa (940 psi) at 1200s. The minimum downcomer temperature at 1200 s was 495K. The extrapolated temperature at 7200 s was 435K. The temperature history was very similar to the first parametric. This parametric variation, therefore, was not risk significant.

7.2.5 Turbine bypass valves fail open (4/4) (TRAC)

The calculation was run to 1200 s and extrapolated to 7200 s.

The same assumptions were made as in scenario #3, with the exception that all four turbine bypass valves failed open. Feedwater to the affected steam generator fails to run back. Level control for auxiliary feedwater flow to the affected steam generator fails. The operator does not restart the reactor coolant pumps. The operator does not throttle HPI.

Primary system pressure decreased ot a minimum of 6.5 MPa (940 psia). HPI actuated at 88 s and pumped the primary system water solid by 1200 s. After that time the pressure remained at the PORV set point of 17 MPa (2450 psig). The calculated downcomer heat transfer coefficient was 1500 W/m²-K. By 1200 s, downcomer fluid temperature had decreased t about 450K (350F). Temperature was extrapolated to decrease to 420K (300F) by 3000 s. At this time the cooldown rate was approximately 60K/hr (100F/hr), which is within the specified maximum cooldown rate. This transient The scenario, therefore, could be on the borderline of possible risk significance.

Two parametric variations were run. The first differed from the base case only in that steam generator level control of auxiliary feedwater in the affected steam generator operated as intended. Pressure history was the same as the base case. Temperature at 1200 s was about 485K. Extrapolated temperature never decreased to 420K. The minimum extrapolated temperature was 450K at 7200 s. This parametric variation, therefore, was not risk significant.

Primary system pressure decreased to the HP) set point in about 150 s. Pressure then increased to the PORV set point as the HPI pumped the primary system water solid by 1000 s. Minimum downcomer temperature of 465K is reached at the end of the calculation (1200 s). The temperature is extrapolated to further decrease to 420K (300F) by 4000 s, and to 365K at 7200 s, at a rate of about 75K (135F) per hour. If the extrapolated temperatures are correct, this case could be pressurized thermal shock significant.

The second parametric variation additionally included operator actions to restart the reactor coolant pumps and throttle HPI. Throttling HPI prevented repressurization. Instead, primary system pressure continued to decline. Pressure was about 6.5 MPA (940 psi) at 1200s. The minimum downcomer temperature at 1200 s was 495K. The extrapolate temperature at 7200 s was 435K. The temperature history was very similar to the first parametric. This parametric variation, therefore, was not risk significant.

7.2.6 2-inch hot leg break (TRAC, RELAP)

TRAC

The calculation was run to 3700 s and extrapolated to 8000 s.

The break is 2-inch diameter and is located in the horizontal section of the surge line. The reactor coolant pumps were tripped 30 s after HPI initiated. HPI initiated at 43 s and was not throttled (subcooling margin criterion was never reached). One parametric variation was run to examining the difference between including LPI or not. The no-LPI case reached a primary system pressure of 2.8 MPa (400 psia) at the end of the calculation. The pressure was extrapolated to remain the same to 7200 s. The downcomer temperature was 480K (405F) and nearly constant at 3700 s, the end of the calculation. Temperature was extrapolated to decrease slightly to 475 K (400F) at 7200 s.

The case with LPI is suspect because injection appears to begin at a pressure of 3.5Mpa (510 psi), while the shutoff head is 1.5 MPa (200 psig). Even at that, the minimum downcomer temperature remains above 420K (300F).

RELAP

The calculation was run to 6200 s and extrapolated to 8000 s.

The reactor coolant pumps were tripped 30 s after HPI initiated. HPI initiated at 79 s. Hot leg A begins to void at 770 s and flow stagnates at 815 s. Hot leg B begins to void at 892 s and flow stagnates at 1020 s.

Primary system pressure decreased over the course of the transient, sufficiently to allow low pressure injection to begin by 1500 s. At that time, pressure stabilizes as injection flow apparently matches break flow. Minimum downcomer temperature drops below 420K (300F) around 5000 s, at which time primary system pressure is about 1.5 MPa (200 psig). The scenario, therefore, could be risk significant.

Comparison of TRAC and RELAP

The primary system pressure decreases more in the RELAP calculation than in the TRAC. That appears to allow more accumulator injection and to drop pressure low enough to allow low pressure injection. The higher injection rates lower the downcomer temperature more in the RELAP calculation than in the TRAC.

	Event	TRAC, s	RELAP, s	Remarks
1	Break opens	0	0
2	Reactor trip	0	45	TRAC scram time is unphysical, incorrect
3	Main feedwater trips	73	70
4	HPI actuates	43	79
5	Reactor coolant pumps trip	71	109
6	Flow stagnation	500	1020
7	Accumulator injection begins	1750	2215	TRAC pressure history is suspect
8	LPI begins	?	5124	TRAC model of LPI is suspect

7.2.7 4-inch hot leg break (TRAC)

The calculation was run to 1400 s and extrapolated to 7200 s.

The break was located in the surge line at the same place as the 2-inch break described in scenario #5. There were no additional failures. Events are accelerated due to the larger break size.

Reactor trip occurred at o seconds. This was incorrectly modeled, similarly to scenario #5. HPI actuated at 17 s. Flow stagnation occurred at 125 s (exactly 1/4 the time for the 2-inch break, as expected). Accumulators begin to inject at 540 s.

Primary system pressure decreased to 1 MPa by the end of the calculation (1400 s) and was extrapolated to further decrease to 0.23 MPa by 3000 s. LPI began injecting at 1236 s. At this time, downcomer temperature fell sharply from 460K to 375K. The pressure at this time was 1.5 MPa (200 psig). The scenario, therefore, could be risk significant., although the pressure is very low when the downcomer temperature drops below 420K (300F).

7.2.8 Rancho Seco Transient (TRAC)

The calculation was run to 4300 s and extrapolated to 7200 s.

The event began as a loss of feedwater leading to a steam generator dryout followed by a steam generator overfeed. Auxiliary feedwater failed to initiate because the control valves did not open, until opened manually by the operators. The reactor coolant pumps remained running. Once begun, auxiliary feedwater remained on until 4200 s. Primary system repressurization was limited to 13.8 MPa (2000 psia) by throttling HPI.

The minimum downcomer fluid temperature of 454K was calculated at 4200 s. TRAC calculated a lower heat transfer coefficient when the reactor coolant pumps are running (15,000 vs 25,000 W/m²-K)

7.2.9 Steam generator overfeed (RELAP)

The calculation ran to 1800s and was extrapolated to 7200s.

This transient initiated with a turbine trip and reactor trip. The main feedwater pumps fail to trip. HPI is initiated on attaining the low pressurizer pressure set point (1500 psig). The operator fails to trip the reactor coolant pumps on low suction pressure. The reactor coolant pumps are not tripped.

The primary system pressure decreased to a minimum of approximately 9 MPa (1305 psia), sufficient to initiate HPI. The reactor coolant pumps were tripped 30s after HPI initiated. Once initiated the HPI filled the primary system water solid and the pressure increased to the PORV set point of 17 MPa (2465 psia). The heat transfer coefficient was approximately 27,000 to 36,000 W/m²-K (it remained high because the reactor coolant pumps were not tripped). The downcomer fluid temperature decreased to a minimum of approximately 510K (459F). The scenario, therefore, was not risk significant.

7.2.10 Stuck open PORV (RELAP)

The calculation ran to 1000s and was extrapolated to 7000s.

HPI was not throttled. The reactor coolant pumps were assumed to remain running for the duration of the transient.

Primary system pressure more or less plateaued at 12 MPa (1700 psia). The heat transfer coefficient was approximately 25,000 W/m²-K (it remained high because the reactor coolant pumps were not tripped). The minimum downcomer fluid temperature was 545K (521F) and occurred at the end of the extrapolation (7000s). The scenario, therefore, was not risk significant.

7.2.11 Main steam line break (RELAP)

The calculation was run to 1500s and extrapolated to 8000s.

In this transient, one reactor coolant pump per loop was restarted ten minutes after attaining 28K (50F) subcooling in both hot legs (actual operator reaction time five minutes based on simulator experience). Auxiliary feedwater to the broken steam generator was isolated ten minutes following event initiation (actual operation reaction time two minutes based on simulator experience). HPI was not throttled.

Primary system pressure decreased to a minimum of approximately 5 MPa around 100s, so HPI was actuated. The reactor coolant pumps were tripped 30s after HPI initiated. The reactor coolant pumps were restarted (one in each loop) ten minutes after attaining 28K (50F) subcooling, at about 1000s.

HPI proceeded to fill the primary system water solid by approximately 800s. Primary system pressure rose to the PORV set point of 17 MPa (2450 psig). The heat transfer coefficient while the reactor coolant pumps were tripped was calculated to be approximately 2000 W/m²-K (400 BTU/hr-ft²-F). Downcomer fluid temperature reached a minimum of approximately 495K (432F). This transient, therefore, was not risk-significant.

7.2.12 Main steam line break (TRAC, RELAP)

TRAC

The calculation was run to 7200 s without extrapolation.

The break was in the steam generator A steam line and was initiated from full power. Feedwater continued to both steam generators for 10 minutes (600 s), at which time it was isolated. Feedwater was restored to the intact steam generator 5 minutes later. The reactor coolant pumps were restarted upon attaining 42K (75F) subcooling. Also, HPI was throttled to maintain 28K to 56K (50F to 100F) subcooling. Other systems were assumed to operate as intended.

HPI initiated at 21 s. Primary system pressure decreased to a minimum of 600 psi by 500 s and then increased thereafter to the PORV set point by 4700 s. The minimum downcomer fluid temperature that was reached was 420K (300F) at 500s at the node where the broken cold leg enters the vessel. This temperature was only briefly obtained and quickly recovered to 460K (370F) and continued to climb when the reactor coolant pumps restarted.

Three parametric variations of this transient were run. Parametric 1 was the same except auxiliary feedwater did not actuate because of an error in the TRAC input deck. Parametric 2 contained the same error as well as an additional error that prevented the reactor coolant pumps from restarting. Parametric 3 tripped the main feedwater at the beginning of the transient and permitted the reactor coolant pumps to restart. The scenario, therefore, was not risk significant.

RELAP

The calculation was run to 2200s and extrapolated to 7200s.

The transient is the same at #10 except the criteria for throttling HPI and restarting the reactor coolant pumps. The reactor coolant pumps were tripped 30 s after initiation of HPI (same as #10). All feedwater to both steam generators was isolated 10 minutes into the event, and restarted to the intact steam generator along with steam dump five minutes later.

In this transient (to be contrasted and compared to transient #2), one reactor coolant pump per loop was restarted ten minutes after attaining 42K (75F) subcooling in both hot legs. The subcooling requirement was reached 300s into the transient. HPI was throttled to maintain 28K to 56K (50F to 100F) subcooling. Other systems were assumed to operate as intended.

The primary system pressure decreased to a minimum of approximately 6.5 MPa (943 psia), then rose to the PORV set point as the HPI pumped the primary system water solid. The minimum downcomer fluid temperature was 494K (429F). The scenario, therefore, was not risk significant.

Comparison of TRAC and RELAP

Table 7-3 compares event timings. The TRAC calculation reaches a lower minimum pressure (650 psi vs 900 psi) at about the same time (500 s) and a lower minimum temperature (420K vs 495K). In both cases, temperature begins to increase upon restart of the reactor coolant pumps. The TRAC heat transfer coefficient is 1800 W/m²-K (RELAP was not given).

Table 7.3

Comparison of Event Timings

	Event	TRAC, s	RELAP, s	Remarks
1	Break opens, reactor trip	0	0
2	Main feedwater pumps trip	48	0	trip in RELAP is spurious due to RELAP modeling of SG level
3	Auxiliary feedwater on	A: 29 B: 49	4	consequence of 2
4	HPI actuates	21	5	RELAP time suspect
5	reactor coolant pumps trip	51	35	30 s after HPI signal
6	Intact SG reaches shutdown level set point of 240 in	347	320
7	75F subcooling regained, reactor coolant pumps restart	526	360
8	Feedwater isolates	600	600	According to prescribed scenario
9	Intact SG unisolates	900	900	According to prescribed scenario
10	PORV set pont reached	4678	2432

7.2.13 Steam generator overfeed (RELAP)

This transient should be compared and contrasted with #9. The calculation was run to 2200s and extrapolated to 7200s.

The transient initiated with a turbine trip and reactor trip. Main feedwater pump trip was assumed to fail. The feedwater pump trip at the steam generator high level set point was also assumed to fail. The feedwater pumps eventually were tripped when water entered the steam lines. HPI initiated at 270s and was not throttled thereafter. HPI proceeded to fill the primary system water solid by 1100s. Primary system pressure decreased to a minimum of approximately 8.5 Mpa (1230 psia) at 500s and increase to the PORV setpoint by 1100s as HPI filled the primary system. The minimum downcomer liquid temperature reached was 500K (440F). The scenario, therefore, was not risk significant.

7.2.14 Turbine bypass valves fail open (4/4) (from hot standby conditions) (RELAP)

The calculation was run to 7200 s without extrapolation. (What was the decay heat?, Was there RCP heat? What was the feedwater temperature - should be 511K/460F)

At time zero, all four turbine bypass valves are opened. They remain open until they are closed after 600 s (10 minutes). HPI was initiated at 125 s and was not throttled thereafter. The reactor coolant pumps were tripped 30s after HPI initiation, at 155 s into the calculation. Main feedwater remained on until 170s into the calculation.

The heat transfer coefficient was approximately 2000 W/m²-K. After reaching a minimum of approximately 4 MPa at 400 s, primary system pressure increased to 17 MPa by 900s as the HPI pumped the primary system water solid. The downcomer fluid temperature decreased below 420K (300F) after approximately 800 s and remained there for the duration of the calculation/extrapolation. The minimum downcomer fluid temperature was 387K (237F). The scenario, therefore, could be risk significant.

It is interesting to note that the temperatures calculated by RELAP for this transient are significantly lower than the TRAC temperatures for transient #4. At least some of the difference may be due to the assumption of low decay heat in the RELAP calculation as opposed to nominal decay heat in the TRAC calculation.

7.2.15 2.5-inch cold leg break (RELAP)

The calculation ran to 6200 s and was extrapolated to 8000s.

The break was in the letdown line, downstream of a motor operated valve that could be closed. The valve was assumed to close after the accumulator are empty.

HPI initiated at 94 s. The reactor coolant pumps were tripped 30 s later.

Loop flow oscillations occurred during the calculation. There was also a significant amount of flow through the vent valves, so the system was well mixed. Calculated plume temperature stayed within 10K of the flowing loop.

The heat transfer coefficient was approximately 1500 W/m²-K. Primary system pressure decreased to about 6 MPa (900 psi) by 700 s and remained about the same for the duration of the transient. The minimum downcomer temperature was about 380F at the end the calculation at 5000 s and extrapolated to be 330F at 8000 s. The scenario, therefore, was not risk significant.

7.2.16 Steam generator tube rupture (RELAP)

The calculation was run to 3000 s and extrapolated to 8000 s.

The transient was initiated from full power initial conditions. The tube break occurs in the A steam generator.

Primary system pressure decreased to a minimum of approximately 11 MPa at 1000s, reaching the HPI actuation set point. The reactor coolant pumps were tripped 30 s thereafter. HPI proceeds to fill the reactor coolant system until it is water solid and the pressure has increased to the PORV setting. Following trip of the reactor coolant pump the heat transfer coefficient decreases to approximately 1500 w/m²-K. The minimum downcomer fluid temperature was 517K (470F). The scenario, therefore, was not risk significant.

7.3 Screening of Transients by Theofanous

Transients were screened to identify those that would lead to loop flow stagnation. Seven scenarios were identified: 1. main steam line break (#11 ); 2. stuck open PORV (#9); 3. steam generator overfeed (#8,#12); (5) steam generator tube rupture #15), Rancho Seco.(#7), and turbine bypass (#3,#4). The fluid temperatures calculated by RELAP and TRAC for these scenarios were deemed adequate.

Oconee PTS Reanalysis

Oconee‑1 is the limiting Duke reactor vessel since it has a PTS value of 297F for the extended license renewal period.

The risk significant cases were

Description	T-H Run	Mean
SBLOCA (2"), HPI on full	3	3E-5
SBLOCA (2.8"), HPI on full	4	3E-7
Large MSLB, EFW feeding faulted SG, HPI on full	25	9E-5
Large MSLB, EFW feeding faulted SG, HPI throttled	27	1E-4
SBLOCA (1"), 2 MS-SRV stuck open, HPI on full, HZP	31	9E-6
Reactor trip, SRV stuck open, HPI on	34	8E-5

Table 3-1 Summary of RELAP5 Cases Analyzed for Oconee
Category	Event
Surge Line Break SBLOCAs (Base Cases)	Transients initiated by a small break LOCA in the pressurizer surge line. The following break diameters (successively doubling the break area) are considered: 2.54 cm (1 in) [Case 1] 3.59 cm (1.414 in) [Case 2] 5.08 cm (2 in) [Case 3] 7.183 cm (2.828 in) [Case 4], and 10.16 cm (4 in) [Case 5] Primary and secondary system functions are assumed to be normal.
Cold Leg Break SBLOCA Sensitivity Cases	Transients initiated by a small break LOCA in the cold leg. The following break diameters are considered: 3.59 cm (1.414 in) [Case 6] 5.08 cm (2 in) [Case 7] Primary and secondary system functions are assumed to be normal.
Surge Line Break SBLOCA cases combined with secondary side failure.	Transients initiated by a small break LOCA in the surge line. The following cases are considered: 2.54 cm (1 in) diameter SBLOCA with 1 stuck open safety valve in steam generator A. [Case 8] 2.54 cm (1 in) diameter SBLOCA w/2 stuck open safety valves in steam generator A. [Case 9] 3.59 cm (1.414 in) diameter SBLOCA w/2 stuck safety valves in steam generator A. [Case 10]
Surge Line Break SBLOCA cases combined with secondary side failure. Operator actions credited.	Transients initiated by a small break LOCA in the surge line. The assumed operator action is to trip or throttle the HPI. The following cases are considered: 2.54 cm (1 in) diameter SBLOCA with 1 stuck open safety valve and HPI terminated when subcooling margin exceeds 55.6 K (100^oF) [Case 11] 2.54 cm (1 in) diameter SBLOCA with 1 stuck open safety valve and HPI throttled to maintain 90 K (50 F) subcooling margin [Case 12] 2.54 cm (1 in) diameter SBLOCA with 2 stuck open safety valves and HPI terminated when subcooling margin exceeds 55.6 K (100^oF) [Case 13]
Surge Line Break SBLOCA Operator Actions Sensitivity Cases.	Transient initiated by a small break LOCA in the surge line. The following cases are considered: 3.59 cm (1.414 in) SBLOCA where the operator is assumed to trip the reactor coolant pumps at 2.778 K (5F) subcooling. Other primary and secondary systems are assumed to be normal. [Case 14] 2.54 cm (1 in) diameter SBLOCA with HPI failure. At 15 minutes after transient initiation, the operator opens both turbine bypass valves to lower primary system pressure and allow core flood tank and LPI injection. [Case 15]
Surge Line Break SBLOCA Decay Heat Sensitivity Cases	Transients initiated by a small break LOCA in the surge line. The assumed decay heat is lowered to 30 % of the original values to determine the impact of decay heat. The following cases are considered: 2.54 cm (1 in) SBLOCA with assumed reduced decay heat generation [Case 16] 2.54 cm (1 in) SBLOCA with reduced decay heat and 1 stuck open safety valve on the steam generator A secondary side. [Case 17]
Reactor Trip with Steam Generator Overfeed or Secondary Side Failure	Transient initiated by a reactor trip. Subsequent failure of the steam generator level control system causes both steam generators to be overfilled. The following cases are considered: Operator is assumed to shut off the emergency feedwater system when the level reaches 96 percent operating range. [Case 18] Emergency feedwater continues running and the steam generators become flooded and remain flooded. Emergency feedwater throttled to maintain flooded steam generators without flooding the steam lines. [Case 19] For the secondary side failure, the following case is considered: Stuck open turbine bypass valve in steam generator A secondary side occurring when the valve opens and subsequently fails to close. The operator throttles HPI to maintain a level of 5.59 m (220 in) in the pressurizer [Case 20]
Turbine Trip with a Primary Side Failure	Transients initiated by a turbine trip. Primary and secondary system functions are assumed to be normal except as listed below. No operator actions credited. The following cases are considered: Turbine Trip [Case 21] Turbine Trip with subsequent failure of the PORV to close [Case 22] Turbine Trip with a stuck open pressurizer safety valve [Case 34]
Turbine Trip with a Secondary Side Failure	Transients initiated by a turbine trip. Primary and secondary system functions are assumed to be normal except as listed below. The following cases are considered: Turbine Trip with subsequent failure of the steam generator level control system that causes both steam generators to become flooded and remain flooded. [Case 23] Turbine Trip with no main feedwater pump trip and failure of steam generator level control system causing both steam generators to become flooded and remain flooded. MFW is tripped when water enters the steamline. [Case 24] Turbine Trip with no main feedwater pump trip and failure of steam generator level control system causing both steam generators to be flooded. Operator is assumed to throttle HPI. MFW is tripped when water enters the steamline. [Case 32] Reactor trip with a stuck open turbine bypass valve. The turbine bypass valve is assumed to reclose in 10 minutes [Case 33]
Reactor Trips with Secondary Side Failure. Operator Action to Throttle HPI Included.	Transient initiated by a reactor trip. A secondary side failure causes one or more safety valves to be stuck open. The following cases are considered: Reactor Trip with one stuck open safety valve in steam generator A. [Case 28] Reactor Trip with one stuck open safety valve in steam generator A and a second stuck open safety valve in steam generator B. [Case 29] Reactor Trip with one stuck open safety valve in steam generator A. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) of level in the pressurizer, whichever is controlling [Case 35]. Reactor Trip with one stuck open safety valve in steam generator A and a second stuck open safety valve in steam generator B. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) level in the pressurizer, whichever is controlling [Case 36].
Reactor Trip Decay Heat Sensitivity Cases.	Transient initiated by a reactor trip. A secondary side failure causes one or more safety valves to be stuck open. A reduced decay heat generation rate set at 30 percent of the full decay heat generation rate is assumed. The following cases are considered: Reactor Trip with one stuck open safety valve in steam generator A and reduced decay heat [Case 30]. Reactor Trip with one stuck open safety valve in steam generator A and a second stuck open safety valve in steam generator B and reduced decay heat. [Case 31] Reactor Trip with one stuck open safety valve in steam generator A and reduced decay heat. Operator is assumed to throttle HPI to maintain 27.8 K (50F)) subcooling or 304.8 cm (120 in) level in the pressurizer, whichever is controlling [Case 37] Reactor Trip with one stuck open safety valve in steam generator A and a second stuck open safety valve in steam generator B and reduced decay heat. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) level in the pressurizer, whichever is controlling [Case 38].
MSLB With and Without Operator Action.	Transient initiated by a severed main steam line in steam generator A at the outlet. The main feedwater pumps and the turbine driven emergency feedwater system are assumed to be shutdown by the MSLB circuitry. The main feedwater system and the startup feedwater systems are isolated by the MSLB circuitry. Three cases are considered: Main Steam Line Break with trip of turbine driven emergency feedwater. [Case 25] Main Steam Line Break without trip of turbine driven emergency feedwater (sensitivity case). [Case 26] Main Steam Line Break with an assumed operator action to throttle HPI to maintain 50 F (27.8 K) subcooling margin. Turbine driven EFW is assumed to remain operating. [Case 27]

| Table 4-1

Summary of Downcomer Temperature and Pressure Results for the Oconee PTS Evaluation | | | | | | --- | | | | | --- | --- | --- | --- |

Transient	Min Down-comer Temp	Time of Min Temp	Corres RCS Press	Comments
	K	sec	MPa
---	---	---	---	---
^oF	psia
---	---	---	---	---
Surge Line Break SBLOCAs (Base Cases)
2.54 cm (1in) surge line break SBLOCA [Case 1]	548	10000	13.8	Temperature drops to 560 K (548^o F) by 4000 seconds (pressure = 14.0 MPa (2031 psia)).
527	2001
3.59 cm (1.414 in) surge line break SBLOCA [Case 2]	498	10000	6.73	Temperature drops to 537 K (507^o F) by 4000 seconds (pressure = 6.67 MPa (967 psia)).
437	976
5.08 cm (2 in) surge line break SBLOCA [Case 3]	325	6800	1.86	Temperature drops to 390 K (242^o F) by 4000 seconds (pressure = 3.0 MPa (435 psia)). Temperature and pressure remains level after 6800 seconds
125	270
7.18 cm (2.828 in) surge line break SBLOCA [Case 4]	303	10000	1.45	Temperature drops to 400 K (260^o F) by 4000 seconds (pressure = 2.24 MPa (325 psia)).
86	210
10.16 cm (4 in) surge line break SBLOCA [Case 5]	295	10000	1.28	Temperature drops to 320 K (116^o F) by 4000 seconds (pressure = 1.22 MPa (177 psia)).
71	186

Cold Leg Break SBLOCA Sensitivity Cases
3.59 cm (1.414 in) cold leg break SBLOCA [Case 6]	497	10000	6.67	Temperature drops to 536 K (505^o F) by 4000 seconds (pressure = 6.11 MPa (886 psia)).
435	967
5.08 cm (2 in) cold leg break SBLOCA [Case 7]	388	10000	2.13	Temperature drops to 463 K (373^o F) by 4000 seconds (pressure = 2.20 MPa (319 psia)).
239	309

SBLOCA Cases Combined with Secondary Side Failure
2.54 cm (1in) surge line break SBLOCA with 1 stuck open safety valve [Case 8]	441	10000	13.2	Temperature drops to 460 K (368^o F) by 4000 seconds (pressure = 12.73 MPa (1846 psia)).
334	1914
2.54 cm (1in) surge line break SBLOCA with 2 stuck open safety valves [Case 9]	420	10000	13.18	Temperature drops to 440 K (332^o F) by 4000 seconds (pressure = 2.73 MPa (396 psia)).
296	1912
3.59 cm (1.414 in) surge line break SBLOCA with 1 stuck open safety valve [Case 10]	414	10000	6.56	Temperature drops to 440 K (332^o F) by 4000 seconds (pressure = 6.27 MPa (909 psia)).
286	951

SBLOCA Cases Combined with Secondary Side Failure. Operator Actions Credited.
2.54 cm (1 in.) surge line break SBLOCA with 1 stuck open safety valve and HPI trip when subcooling margin exceeds 55.6 K (100^o F) [Case 11]	480	2200	3.86	After 2200 sec, temperature rises to 560 K (548^o F) by 6600 seconds and remains between 530 K and 560 K (494^o F and 548^o F) for the rest of the transient. Pressure remains between 5.0 and 7.2 MPa (725 and 1044 psia).
404	560
2.54 cm (1 in) SBLOCA with 1 stuck open safety valve and HPI throttled to maintain 90 K (50 F) subcooling margin [Case 12]	460	10000	2.69	Temperature drops to 440 K (332^o F) by 4000 seconds (pressure = 3.47 MPa (503 psia)).
368	390
2.54 cm (1 in) SBLOCA with 2 stuck open safety valves and HPI tripped when subcooling margin exceeds 55.6 K (100^o F) [Case 13]	408	10000	1.48	Temperature drops to 442 K (335^o F) by 4000 seconds (pressure = 1.48 MPa (215 psia)).
275	215

SBLOCA Operator Action Sensitivity Cases
3.59 cm (1.414 in) SBLOCA where the operator is assumed to trip the RCPs at 2.778 K (5 F) subcooling. [Case 14]	400	10000	6.14	Temperature drops to 458 K (364^o F) by 4000 seconds (pressure = 6.35 MPa (921 psia)).
260	891
2.54 cm (1 in) SBLOCA with HPI failure. At 15 minutes after transient initiation, the operator opens both TBVs to lower primary system pressure and allow core flood tank and LPI injection. [Case 15]	340	7000	1.0	Temperature drops to 390 K (242^o F) by 4000 seconds (pressure = 2.18 MPa (316 psia)).
152	145

SBLOCA Decay Heat Sensitivity Cases
2.54 cm (1 in) SBLOCA with assumed reduced decay heat generation [Case 16]	490	10000	13.3	Temperature drops to 526 K (487^o F) by 4000 seconds (pressure = 13.19 MPa (1913 psia)).
422	1929
2.54 cm (1 in) SBLOCA with reduced decay heat and 1 stuck open safety valve on the steam generator A secondary side. [Case 17]	417	820	7.98	Temperature drops to 440 K (332^o F) by 4000 seconds (pressure = 13.93 MPa (2020 psia)).
291	1157

Reactor Trip with Steam Generator Overfeed or Secondary Side Failure
Reactor trip with SG level control failure causing both SGs to be overfilled. Operator is assumed to shut off the EFW system when the level reaches 96 % operating range. [Case 18]	540	870	12.25	Temperature rises to 625 K (665^o F) by the end of the transient (pressure = 16.91 MPa (2453 psia)).
512	1777
Reactor trip with SG EFW level control failure causing both SGs to become flooded and remain flooded. EFW throttled to maintain flooded SGs without flooding the steam lines. [Case 19]	537	940	12.16	Temperature rises to 561 K (550^o F) by 1800 seconds (Pressure = 15.34 MPa (2225 psia)) and remains level for the rest to the transient (pressure = 13.0 MPa (1885 psia) at the end of the transient ).
507	1764
Reactor trip with a stuck open turbine bypass valve in SG-A. The operator throttles HPI to maintain a level of 5.59 m (220 in) in the pressurizer [Case 20]	477	10000	12.11	Temperature drops to 490 K (422^o F) by 4000 seconds (pressure = 13.60 MPa (1972 psia)).
399	1756

Turbine Trip with Primary Side Failure
Turbine trip [Case 21]	560	450	14.0	After 560 seconds, temperature remains level for the rest of the transient (Pressure = 13.53 MPa (1962 psia) at the end of the transient ).
548	2031
Turbine trip with subsequent failure of the PORV to close [Case 22]	518	10000	9.04	Temperature drops to 551 K (532^o F) by 4000 seconds (pressure = 10.19 MPa (1478 psia)).
473	1311
Turbine trip with a stuck open pressurizer safety valve [Case 34]	320	10000	1.49	Temperature drops to 395 K (251^o F) by 4000 seconds (pressure = 2.21 MPa (320 psia)).
116	216

Turbine Trip with Secondary Side Failure
Turbine trip with subsequent failure of the steam generator level control system that causes both steam generators to become flooded and remain flooded. [Case 23]	510	2000	13.12	Temperature gradually rises to 515 K (467^o F) by 5500 seconds (pressure = 15.0 MPa (2176 psia)) then drops to 510 K (458^o F) by the end of the transient (pressure = 14.65 MPa (2125 psia)).
458	1903
Turbine trip with no MFW pump trip and failure of SG level control system causing both SGs to become flooded and remain flooded. MFW is tripped when water enters the steamline. [Case 24]	554	300	11.87	Temperature rises to 560 K (548^o F) by 600 seconds (pressure = 15.10 MPa (2190 psia)) and remains level for the rest of the transient (pressure = 13.75 MPa (1994 psia)) .
538	1722
Turbine trip with no MFW pump trip and failure of SG level control system causing both SGs to be flooded. Operator is assumed to throttle HPI. MFW is tripped when water enters the steamline. [Case 32]	554	300	11.87	Temperature rises to 560 K (548^o F) by 600 seconds (pressure = 15.1 MPa (2190 psia)) and remains level for the rest of the transient (pressure = 13.74 MPa (1992 psia)).
538	1722
Reactor trip with a stuck open turbine bypass valve. The turbine bypass valve is assumed to reclose in 10 minutes [Case 33]	530	600	15.11	Temperature rises to 562 K (552^o F) by 1500 seconds (pressure = 17.24 MPa (2500 psia)) and remains level for the rest of the transient (pressure = 15.14 MPa (2196 psia)).
494	2192

Reactor Trip with Secondary Side Failure. Operator Action to Throttle HPI Included.
Reactor trip with one stuck open safety valve in SG-A. [Case 28]	455	10000	17.44	Temperature drops to 477 K (399^o F) by 4000 seconds (pressure = 17.09 MPa (2479 psia)).
359	2529
Reactor trip with one stuck open safety valve in SG-A and a second stuck open safety valve in SG-B. [Case 29]	431	10000	17.28	Temperature drops to 446 K (343^o F) by 4000 seconds (pressure = 17.2 MPa (2495 psia)).
316	2506
Reactor trip with one stuck open safety valve in SG-A. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) of level in the pressurizer [Case 35].	476	10000	11.25	Temperature drops to 490 K (422^o F) by 4000 seconds (pressure = 12.91 MPa (1872 psia)).
397	1632
Reactor trip with one stuck open valve in SG-A and a second stuck open safety valve in SG-B. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) level in the pressurizer [Case 36].	445	10000	8.21	Temperature drops to 453 K (356^o F) by 4000 seconds (pressure = 10.0 MPa (1450 psia)).
341	1191

Reactor Trip Decay Heat Sensitivity Cases
Reactor trip with one stuck open safety valve in steam generator A and reduced decay heat [Case 30].	435	10000	17.47	Temperature drops to 455 K (359^o F) by 4000 seconds (pressure = 17.15 MPa (2487 psia)).
323	2534
Reactor trip with one stuck open safety valve in SG-A and a second stuck open safety valve in SG- B and reduced decay heat. [Case 31]	413	10000	17.3	Temperature drops to 431 K (316^o F) by 4000 seconds (pressure = 17.2 MPa (2495 psia)).
284	2509
Reactor Trip with one stuck open safety valve in SG-A and reduced decay heat. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) level in the pressurizer [Case 37]	458	10000	11.22	Temperature drops to 471 K (388^o F) by 4000 seconds (pressure = 12.76 MPa (1851 psia)).
365	1627
Reactor Trip with one stuck open safety valve in both SG-A and SG-B and reduced decay heat. Operator is assumed to throttle HPI to maintain 27.8 K (50F) subcooling or 304.8 cm (120 in) level in the pressurizer [Case 38].	429	10000	7.84	Temperature drops to 442 K (336^o F) by 4000 seconds (pressure = 9.54 MPa (1384 psia)).
312	1137

Main Steam Line Break
Main Steam Line Break with trip of turbine driven emergency feedwater [Case 25].	380	5000	17.3	After 5000 seconds, temperature remains level (pressure = 17.3 MPa (2509 psia) for the rest of the transient).
224	2509
Main Steam Line Break without trip of turbine driven emergency feedwater (sensitivity case) [Case 26].	380	4000	17.3	After 4000 seconds, temperature remains level (pressure = 17.3 MPa (2509 psia) for the rest of the transient).
224	2509
Main Steam Line Break with an assumed operator action to throttle HPI to maintain 50 F (27.8 K) subcooling margin. Turbine driven EFW is assumed to remain operating [Case 27].	380	5000	1.5	After 5000 seconds, temperature remains level (pressure = 1.75 MPa (254 psia) for the rest of the transient).
224	218

TRAC Reanalysis

I completed 3 TRAC calculations (SG overfeed to 96%, turbine bypass valve stuck open, and main steam line break) and generated a set of plots comparing TRACM and RELAP5. The minimum downcomer temperatures which are most important are remarkably close even though other things are considerably different.

Main Reason of Discrepancy between TRAC and RELAP

1. SG Overfeed to 96% (RELAP case 19)

Incorrect implementation of SG safety relief valves in TRAC, resulting in safety relief valve opening about 8% lower than the set point. As a result, safety relief valves are modulating in TRAC while turbine bypass valves are modulating in RELAP. LANL is revising the deck now to correct this.

2. Turbine Bypass Valve (RELAP case 35)

HPI throttling logic was applied in TRAC while it was not in RELAP. In TRAC case, a minimum of 50 F subcooling and other HPI throttling criteria, as described by Oconee, are used before HPI is throttled.

3. Main Steam Line Break (RELAP case 27)

HPI throttling logic was applied in TRAC while not in RELAP. Other comments same as above in No. 2.

Transient	Code	T_min in DC, K	P in DC, MPa	h_min in DC, W/m²K	h_min in DC, W/m²K
96% SG Overfeed	TRAC	541	13.4	22,000	27,500
	RELAP	536	12.7
TBV Stuck Open	TRAC	475	3.0	22,000	28,500
	RELAP	475	12.0
MSLB	TRAC	376	15.7	18,000	23,600
	RELAP	378	17.2

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