TECHNICAL FIELD

The invention relates to a power plant and to a method for its operation. More specifically, the invention relates to improved primary frequency controlling capabilities of steam power plants having dry or dry/wet cooling systems. The invention can be preferably applied for power plants having high steam parameters (e.g. supercritical or ultra-supercritical power plants) equipped with dry or dry/wet cooling systems, configured and operated to provide frequency controlling for the power grid.

BACKGROUND ART

The continuously growing share of renewables in electricity production has gradually been shifting the load profile of steam power plants from baseload to a more flexible one. Besides operating also at intermediate load, the new requirements may include the need to participate in frequency control as well. Such a capability makes steam power plants more valuable for the power system. Meanwhile, there is an explicit tendency to build coal fired power plants with supercritical or ultra-supercritical steam cycles aiming at high efficiency paired with reduced environmental impact. Such power plants shall apply once-through boilers, which - against drum-type ones - have low thermal inertia. This imposes a challenge on these modern power cycles to satisfy especially primary frequency control (PFC) demands of the grid, and in a smaller extent may affect also their secondary frequency control (SFC) capabilities, both requiring a power increase operating mode of the power plant.

The most critical among the energy balancing and frequency controlling tasks in a power system is the primary frequency control. Its objective is to stop further reduction of frequency, and realizing a balance between momentary generation and load. It is automatically activated at a specified frequency deficiency with a response time varying within 2-30 seconds. The expected output jump is 2-10% throughout a period of operation, being approximately 5-10 minutes. The PFC period shall be followed by the secondary frequency control (SFC), its objective is reinstating nominal frequency by balancing power deficit or surplus. It is activated regionally within 30 sec followed a stronger disturbance or simultaneously with the primary control. The required response time is within ~1-5 minutes, and the expected period of operation is ~10-20 minutes. The actual figures depend on the grid code of the specific power system.

A number of solutions have been developed aiming at improving the PFC and SFC capabilities of such power plants, e.g.:

- releasing throttling reserve of the turbine control valve and/or opening the still unused control valve in case of turbines having multi-valve control section at loads under 100%;

- opening high pressure (HP) turbine section bypass valve (overload valve), if exists;

- throttling (incl. eventually completely closing) the condensate flow to the low pressure (LP) and intermediate pressure (IP) feed-water heaters up to and including the deaerator/feed-water tank;

- bypassing high pressure (HP) feedwater heaters;

- additional spraying into the superheated (SH) and reheated (RH) steam flow;

- increasing fuel input of the boiler.

Generally, when a need for PFC arises, providing an optimal response justifies an integrated and simultaneous use of several of these methods. It is notable that among these different groups of solutions the condensate throttling/stop is always included, representing a kind of ‘backbone’ of the PFC processes. It is because also supercritical steam cycles have a further less volatile source of thermal inertia: the hot water stored in their feedwater tank. This thermal energy can efficiently be activated by the condensate throttling/stop method to provide additional power output during the PFC operation period. In fact, it is bridging the time gap required for boiler load-up - at least partially. These features make it a superior option and enhancing its importance. Since the 1980s several patent documents and a large number of technical articles/studies have been published for solutions based on or including condensate throttling/stop (i.e. reducing or stopping steam extraction from the relevant IP/LP bleedings) for realizing PFC operation. Those are exclusively related to power cycles incorporating surface type condensers. It is the same in cases of realized applications of the process.

As prior art, reference is made to US 6,134,891 , GB 2131929 B, DE 43441 18 C2 and EP 2351914 B1 , as well as to the following articles:

- Cziesla F, Bewerunge J, Senzel A: Liinen - state-of-the-art ultra supercritical steam power plant under construction; PowerGen Europe 2009, Cologne, Germany;

- Dr. Quinkertz R, Ulma A, Gobrecht E, Wechsung M: USC Steam Turbine technology for maximum efficiency and operational flexibility; PowerGen Asia 2008 Kuala Lumpur, Malaysia;

- Achter T (Siemens): Dynamic operation of coal-fired power plants in volatile grids; Bangkok 2015-09-01 ; and

- Mercier J, Lambert L (Alstom): Dynamic coal-fired power plants to secure electrical grids, 2013.

To describe the prior art, a simplified process diagram is depicted in Fig. 1 for a high pressure steam power plant equipped with a surface condenser 36. The power plant is adapted for primary frequency control operation, and comprises a power cycle comprising

- a boiler 9, a superheater 9a, a turbine control valve 31 and a reheater 9b, all downstream the boiler 9;

- a turbine set fed by steam from the boiler 9, the turbine set having a high pressure turbine section 32, an intermediate pressure turbine section 33 and a low pressure turbine section 34,

- a surface condenser 36 receiving expanded steam from the low pressure turbine section 34, the surface condenser 36 having a hotwell 37, and cooling water is circulated to the surface condenser 36 by a cooling water circulating pump 35; - a feedwater tank 4 supplied with condensate from the hotwell 37 by means of a condensate extraction pump 38, the boiler 9 being fed from the feedwater tank 4 by means of a feedwater pump 8,

- a condensate control valve 39 adapted for throttling a flow of the condensate in case a power increase is needed, the condensate control valve 39 being arranged between the condensate extraction pump 38 and the feedwater tank 4,

- one or more steam extraction lines 21-24 leading from the intermediate pressure turbine section 33 or from the low pressure turbine section 34 to a preheating means for ensuring that preheated condensate is collected in the feedwater tank 4; wherein the preheating means may comprise feedwater heater(s) or/additionally it can be realized within and by the feedwater tank 4; and

- further steam extraction lines 25-27 leading from the high pressure turbine section 32 to further feedwater heaters 5-7 included between the feedwater tank 4 and the boiler 9.

The condensate throttling is initiated via throttling the condensate control valve 39. Steam extraction valves 11-14 (wherever they exist) of the steam extraction lines 21-24 leading to corresponding pre-heaters, i.e. feedwater heaters 1-3 can be adapted to the change in condensate flow rate, i.e. the steam extraction valves 11- 14 can be controlled according to a throttling state of the condensate control valve 39. Alternatively the process can be started by activating these fast closing steam extraction valves 11-14. The condensate flow may be even completely stopped by the condensate control valve 39, in which case the maximal throttling state is a closed state of the condensate control valve 39. Meanwhile the unused extra condensate is collected in a hotwell 37 of the surface condenser 36. During the condensate throttling the warm feedwater towards the boiler 9 is taken from the feedwater tank 4, without changing either its quantity or its temperature. That is, making use of the stored thermal energy in the feedwater tank 4.

The throttled (or stopped) condensate flow rate reduces/stops steam flow to the relevant IP and LP feedwater heaters 1 , 2, 3 (pre-heaters) and to the deaerator/feedwater tank 4. Thus, steam expanding in the relevant intermediate pressure and low pressure turbine sections 33, 34 increases - resulting in a surplus power generation.

Main features of condensate throttling are as follows:

- provides valuable thermal inertia to the power cycle via hot water stored in the feedwater tank;

- responds with power increase within 2-3 seconds, though development of the full extra power output takes approx. 10-30 seconds from initiating the process;

- it does not need any specific change in turbine or boiler construction;

- it has no or only minor effect on the turbine and boiler efficiency or on the heat rate during the process.

However, it is clear that the intensity and the time-extent of the surplus energy/output heavily depends on the storing capacity of the feedwater tank 4 and that of the surface condenser hotwell 37.

Generally, the extra storing capacity of a feedwater tank 4 is in the range of 5-10 minutes based on the water volume corresponding to a difference between a normal level (being a desired level to which the level of the feedwater tank 4 is controlled) and a low level. It is in more or less satisfactory for PFC needs. However, the surplus storing capacity of a surface condenser hotwell 37 - between the normal and maximum water levels - is about 3-5 minutes. Considering that in case of condensate throttling/stop process the flow rate of water into the condenser hotwell 37 is increased by further several percentages, the period for storing the required volume in the surface condenser hotwell 37 is even shorter by the same percentage.

Thus the process requires an additional condensate storing capacity especially for the condenser. However, enlarging the surface condenser hotwell 37 is problematic because the condenser is arranged under the low pressure turbine section 34, in a location where it is difficult to find any extra space. There are some suggestions (e.g. in DE 3304292 C2) to use an additional storage tank for the unused condensate at a different area of the turbine hall. Considering the necessary connections, instrumentation and controlling accessories - besides the extra costs of these - it is an unfavourable solution as proved in the practice.

Taking the given water storing capacities of the surface condenser 36 and the feedwater tank 4, EP 2351914 B1 suggests to apply enhanced fuel supply into the boiler 9 by applying an additional standby silo for grinded coal. When PFC operation starts, activating this standby buffer silo reduces the required time for increasing the load of the power plant, i.e. increasing its output in a reduced period. This is intended to counter the drawbacks caused by the short period of the power increase achievable by condensate throttling/stop due to the above mentioned limited storing capacities. The suggested solution, although successful, requires a high investment cost and a further complication of the power system and PFC process.

This underlines again the need that the power cycle shall have satisfactory storing capacities both at its feedwater tank and at the condenser hotwell.

DESCRIPTION OF THE INVENTION

It is an object of the invention to provide and operate indirect dry cooling systems (Heller System) and their dry/wet derivatives equipped with direct contact (DC) or hybrid (DC&surface) condensers serving high parameter steam power plants in a way to improve the power plants condensate throttling/stop based primary frequency control capability and extending it into the secondary frequency control period. This object is achieved by making use basically of the existing construction and arrangement of the dry cooling circuit having a DC condenser with minimal additions and modification of some of its elements and its operational characteristics - to improve frequency control capabilities.

Thus, the invention is a power plant adapted for primary frequency control operation according to claim 1 , and a method for operating the power plant according to claim 10. Preferred embodiments are defined in the dependent claims. The invention makes use of the fact that in case of dry cooling systems comprising direct contact condensers, the cooling water is of condensate quality. Therefore the storing capacity of the dry cooling system (including its storage tank(s)) can be used for temporary storage of withhold condensate, and after the throttling phase, levels in the power plant can be reinstated from the storage tank(s).

BRIEF DESCRIPTON OF THE DRAWINGS

In the following, exemplary preferred embodiments of the invention will be described in details with reference to the drawings, in which

Fig. 1 is a schematic connection diagram of a prior art high pressure steam power plant with a surface condenser,

Fig. 2 is a schematic connection diagram of an embodiment of a dry cooled high pressure steam power plant having a direct contact condenser with a conventional condensate pump,

Fig. 3 is a schematic connection diagram of an embodiment of a dry cooled high pressure steam power plant having a direct contact condenser with a condensate booster pump, and

Fig. 4 is a schematic connection diagram of an embodiment of a dry cooled high pressure steam power plant having a direct contact condenser with a condensate booster pump, arranged to enable the stop of the condensate booster pump.

MODES FOR CARRYING OUT THE INVENTION

Figs. 2, 3 and 4 depict simplified connection diagrams of a steam power plant having a Heller System, i.e. an indirect dry cooling system 80 comprising a direct contact condenser 56. The power cycle is basically the same as it is in the case of power plants equipped with surface condensers 36, such as that in Fig. 1. Accordingly, during the condensate throttling process the operational steps are similar as described previously in case of power cycles having surface condensers 36. The differences come from the connections of the power cycle to the surface condenser 36 versus the direct contact condenser 56 and from the inclusion of an indirect dry cooling system 80. ln the context of the present application, the term throttling covers any reduction of the throughput, including full closure as well.

The simplified connection diagrams are only for explaining the relations among the most important elements. The number and positions of steam extractions and feedwater heaters can be different, although as a minimum at least one steam extraction, preferably leading to the feedwater tank 4 shall be applied. The power plant preferably comprises more than one steam extraction line 21-24 leading from various locations of the turbine set to the feedwater heaters 1-3 and/or to the feedwater tank 4, each having a respective steam extraction valve 11-14.

The waste heat from the power cycle is initially exchanged in the direct contact condenser 56 by condensation taking place on cold cooling water film jets. The warmed up cooling water and condensate mixture is extracted by a cooling water circulating pump 65 from a hotwell 57 of the direct contact condenser 56. A major part of the mixture (approx. 97%) is circulated throughout the dry cooling circuit comprising a forwarding main line 67 and a returning main line 68. Between the main lines there is a network of distribution and collecting piping supplying water to and from air coolers 71 , being preferably cooling deltas. By the air coolers 71 heat is dissipated into the air. The re-cooled cooling water flows back to the direct contact condenser 56 via the returning main line 68 and preferably either through a recovery hydro turbine 66 or a cooling water throttling valve.

The dry cooling system 80 is preferably a completely closed cooling water circuit filled by condensate quality water. The cooling air is moved by a natural and/or a mechanical draft cooling tower 70 comprising the air coolers 71.

From the cooling water and condensate mixture the quantity corresponding to that of the condensate (approx. 3%) is taken out and recirculated into the feedwater line either directly from the direct contact condenser hotwell 57 by a regular condensate extraction pump 38 (see Fig. 2) or by a condensate booster pump 58 (see Fig. 3) via the condensate control valve 39. If the more preferable condensate booster pump 58 option is applied, then water is taken from a discharge branch of the cooling water circulating pump 65, as depicted in Figs. 3 and 4.

The cooling water circuit is equipped with one or more underground storage tanks 72 located close to the area of the air coolers 71 , storing condensate quality cooling water for draining/refilling air coolers, and having valve connections to the cooling water mains and to the distributing/collecting piping. One of these valves is usually a fine level control valve 74 for fine level setting of the direct contact condenser 56 in a normal operation. There are usually valves for draining the separated sections of air coolers 71 , during scheduled stops and there is usually one for emergency draining of the whole indirect dry cooling circuit.

The at least one underground storage tank 72 is equipped with a refilling pump 75 as well, and a refilling line with a refilling valve 76 is leading from the storage tank 72 to the cooling circuit, preferably to the forwarding main line 67. During a stop of the power plant in a cold weather, the air coolers 71 and their above-ground distributing and collecting piping shall be drained into the underground storage tanks 72 to avoid freezing damage and meanwhile preserving the valuable large volume of condensate quality water. In case of restarting the power plant, the air coolers 71 are refilled section by section using the refilling pump 75, (being preferably submersible pumps) through the sector piping connected to the forwarding main line 67.

There is a discharge line with a discharge control valve 73 leading from the dry cooling circuit to the storage tank 72, preferably connected to the dry cooling circuit at the returning main line 68 and/or at the forwarding main line 67, which discharge control valve 73 can automatically be actuated (opened, closed, regulated) during the condensate throttling/stop process based on the water level in the hotwell 57 of the direct contact condenser 56. The discharge control valve 73 shall be selected/dimensioned to be able for handling a maximum water flow rate (i.e. to have a maximal throughput) corresponding to the excess condensate flow rate into the direct contact condenser hotwell 57 caused by the maximal throttling state, e.g. by a full condensate stop mode, to avoid its accumulation in the condenser hotwell - IQ -

57, and shall be able to discharge the balance flow rate into the hotwell 57 (i.e. a sum of all incoming flow rates less a sum of all outgoing flow rates) into the storage tank(s) 72. Accordingly, the discharge control valve 73 has a maximal water flow rate which is not lower than the balance flow rate (in other words: surplus flow rate) into the hotwell 57 of the direct contact condenser 56 when the condensate control valve 39 is in a maximal throttling state. It is noted that the cooling water arriving from and leaving to the dry cooling circuit may be excluded from the balance, if it is in a steady circulation during the condensate throttling period. Thus, the level in the hotwell 57 is primarily determined by the balance flow rate of the condensate originating from the power cycle in the form of expanded steam to be condensed or already in a condensate form. Opening the discharge control valve 73 avoids an increase of water level in the hotwell 57 of the direct contact condenser 56 above an allowable maximum level. This latter level can be easily selected by a skilled person according to the given circumstances.

Generally the required storing capacity of the storage tank(s) 72 is higher by approx an order of magnitude than what is needed during the condensate throttling/stop process. Therefore, increasing the total storing capacity of the storage tank(s) 72 by 5-10% gives a satisfactory condensate stop operation for 15- 20 minutes. However, there may be no need for enlarging the underground storage tank(s) 72, since those are nearly empty most of the time, and coincidence of a power plant stop at freezing danger and a PFC operation has a very low probability. In such a case, due to the built-in reserve of the volume capacity of the underground storage tank(s) 72 is close to cover the added volume accumulated during a full condensate stop PFC operation. Even in a possible worst case event, only a few percent of the condensate may be lost (rejected into a rain drain), if the underground storage tank(s) 72 storing capacity remains the original. Decision about the need and the extent of enlarging the underground storage tank(s) 72 shall be made in the light of the above circumstances.

It is satisfactory to maintain the same level range in the direct contact condenser hotwell 57 during condensate throttling/stop period as in normal operation. However, further improvement can be achieved if maintaining a somewhat reduced range of water level in the direct contact condenser hotwell 57 by means of the discharge control valve 73. In this case the minimum water level is kept at about the normal water level of the normal operation and as an upper value is kept at or close to the level like that of the high level in normal operation.

When the water level in the feedwater tank 4 reaches the allowable minimum level or whenever the need for PFC (and SFC) periods by condensate throttling/stop are over (i.e. power increase is no more needed), the process is terminated and a reinstating is initiated. In this reinstating phase, the discharge control valve 73 is closed and the condensate control valve 39 and preferably also the steam extraction valves 11-14 are opened, preferably all simultaneously. Further, preferably a condensate recirculating valve 41 is closed, while the condensate extraction pump 38 or the condensate booster pump 58 - called together as the condensate pump - shall be operated with full capacity throughout reinstating the full condensate throttling/stop capability to be applied in a next round of PFC. Essential part of the reinstating process is to reinstate the normal water levels in the feedwater tank 4 and of the direct contact condenser 56 - as well as the original water level in the underground storage tank(s) 72.

In the reinstating process - as a part of it - to contribute to the enhanced condensate supply into the feedwater tank 4, the refilling pump(s) 75 - located at the cooling tower underground storage tank(s) 72 - shall be operated to supply extra water into the direct contact condenser 56 via a reinstating line having a reinstating valve 77, connected preferably to the returning main line 68 or to the forwarding main line 67. From the hotwell 57 of the direct contact condenser 56 the condensate extraction pump 38 or the condensate booster pump 58 through the feedwater heaters 1-3 (operative again) refills the water volume into the feedwater tank 4, thereby reinstates the water level therein. According to the invention, the refilling pump 75 shall have a maximal flow rate which is not lower than flow rate of the full capacity of the condensate pump 38, 58; in this case the speed of the reinstating process is not limited by the throughput of the refilling pump 75. The corresponding water volume previously was temporally discharged into the underground storage tank(s) 72 - thus, it is necessary to reinstate the original levels in both, in the underground storage tank(s) 72 and in the feedwater tank 4. During this refilling period a make-up water valve 42 of the direct contact condenser 56 shall remain inactive, i.e. closed.

Setting and maintaining the direct contact condenser 56 level during condensate throttling/stop process, then terminating the process and reinstating the condensate stop capability shall be covered by a separate control sequence. Its operation (i.e. taking over controlling of the related elements) is to be initiated automatically according to the grid requirement and finished when the reinstating process is completed.

Two options may be applied for the condensate pumps:

- applying a conventional condensate pump as a condensate extraction pump 38 taking water from the direct contact condenser hotwell 57 (Fig. 2); or

- applying a condensate booster pump 58 instead, taking water from the discharge branch of the cooling water circulating pump 65 (Figs. 3 and 4).

Even from point of view of normal operation, condensate is preferably taken from the discharge branch of the cooling water circulating pump 65, i.e. the condensate booster pump 58 is applied, by which the need for a more sophisticated and expensive conventional condensate extraction pump 38 is eliminated.

The indirect dry cooling system 80 comprising the direct contact condenser 56 and having the cooling water circulating pump 65 - independently if a conventional condensate extraction pump 38 or a condensate booster pump 58 is applied - brings further advantages when the power plant participates in PFC/SFC operations, if realised by a complete condensate stop process.

During the power increase operating mode, the condensate control valve 39 may be closed and/or the condensate pump 38, 58 may be stopped. The condensate extraction pump 38 or the condensate booster pump 58 is than shut off, and then the required condensate water for some auxiliaries can be taken through a cold auxiliary condensate valve 43. It is connected to the discharge branch of the cooling water circulating pump 65. The warmed up water from the auxiliaries (following a pressure loss) is returned either into the suction branch of the cooling water circulating pump 65 or alternatively into the direct contact condenser 56 via a warm auxiliary condensate valve 44. The pressure difference available for covering the pressure drop to / in the auxiliaries is about 3 - 3.5 bar. It shall be mentioned, that the flowrate of the water to / back the auxiliaries is in the range of 0.1 % of that of the complete cooling water circulating pump 65 flowrate, therefore its temperature effect is practically negligible. By this solution the recirculated condensate volume into the condenser hotwell 57 can be minimized, since there is no need to maintain the so called‘pump minimum flow rate’ through the condensate recirculating valve 41. Accordingly, there is no need for the power that otherwise would be necessary for driving the condensate extraction pump 38 or the condensate booster pump 58 in this period (i.e. the power plant net output is further increased). See Fig. 4 for this arrangement in case of using the condensate booster pump 58.

The strong dependence of the surplus output and its period available at condensate throttling/stop highlights the importance of extra water storing capacities of the condenser and of the feedwater tank 4.

In case of applying a surface condenser 36, generally its storing capacity is the limiting factor compared to that of the feedwater tank 4. Whereas, application of a direct contact condenser 56 in the above inventive way reverses this relation between the storing capabilities in favour of the condenser. Therefore, it is worthwhile to reduce the imbalance between their capabilities by applying a feedwater tank 4 with an enlarged volume capable to store an amount of feedwater being e.g. equivalent for at least 15 minutes during condensate stop operation, measured between the normal water level and the minimum water level of the feedwater tank 4. From this point of view it is important to note that an increase in the storing capacity of a feedwater tank 4 is significantly easier due to its usual location than it was e.g. for a surface condenser 36.

In a high parameter steam power plant cooled by a dry cooling circuit or by a dry/wet cooling system having either a direct contact condenser 56 or a surface condenser 36, air coolers 71 may be equipped with an emergency spraying installation which is able to sprinkle fine water drops on the air side surface of the air coolers. This operation is preferably initiated at ambient temperatures above 15 °C, whenever either PFC or SFC operation is on or during both. Supplementary spraying of air coolers of a dry or dry/wet cooling plant is a known solution to reduce turbine backpressure and to thereby increase power output at high ambient temperature conditions. It shall be mentioned that the extent and period of such spraying shall be limited to avoid unwanted depositions on the heat transfer surface of air coolers 71.

In general the PFC and SFC operations are about to produce surplus output within some seconds for a period of 5-20 minutes per case. This is a limited time even if adding all these periods throughout a whole year. Thus, applying the presumably existing supplementary spraying system, also for enhancing the output at elevated ambient temperatures during PFC/SFC operations, does not mean either excessive use of spraying or extra investment costs. It is noted that applying such‘emergency spraying’ is feasible for any dry or dry/wet cooling system, independently whether it is equipped with direct contact condenser or with a surface condenser.

Summarising, condensate throttling represents a core value within PFC methods applicable for high-pressure steam power plants. Its use provides a significant contribution to fulfil grid requirements and meanwhile improving plant efficiency. Indirect cooling systems or their dry/wet derivatives when equipped with direct contact condensers make easier condensate throttling for power plants. Furthermore, adapting their basic configuration by changing / adding some elements and applying specific operation measures even can help to increase the surplus power and length of its period based on condensate throttling/stop PFC operation mode and able to extend it from the PFC mode into that of the SFC - if required.

Thus, the inventive steam power plant is equipped and arranged to facilitate its primary frequency control operation via (or including also) condensate throttling/stop by the condensate control valve 39 and preferably also by throttling/closing the steam extraction valves 1 1-14 including that of the intermediate pressure feedwater heater/deaerator together with the feedwater tank 4 and those of the further lower pressure feed-water heaters, wherein the expanded steam from the low pressure turbine section 34 is condensed by either a direct contact condenser 56 or by a hybrid condenser having surface and a direct contact condenser segment/part, and wherein a dry or dry/wet cooling system dissipates heat from the condenser. The indirect dry cooling system 80 has its usual elements:

- the closed dry cooling water system filled by condensate quality water in the whole circuit, including the forwarding main line 67 with the cooling water circulating pump 65 forwarding cooling water from the direct contact condenser 56 to the air coolers 71 , and the returning main line 68 connected to the direct contact condenser 56 via either a recovery hydro turbine 66 or a cooling water throttling valve;

- the natural or mechanical draft cooling tower 70 (or their combination) comprising the air coolers 71 (so-called‘cooling deltas’);

- cooling water distributing/collecting piping for air coolers; and

- storage tank(s) 72 storing condensate quality cooling water for temporary draining/refilling air coolers 71 and having valve connections to the cooling water mains and to the distributing/collecting piping and being equipped with refilling pump(s) 75. The a storage tank(s) 72 is (are) arranged at a lower level than the air coolers 71 , and is (are) preferably underground storage tank(s) 72.

The water discharge control valve 73, connected preferably to the returning main line 68 and/or to the forwarding main line 67 (looked from the direct contact condenser 56), is actuated - opened or closed - based on the water level in the direct condenser 56, wherein the discharge control valve 73 is specifically suitable for handling the maximum water volume corresponding to the complete condensate flow to the direct condenser 56 even at full condensate stop mode and is able to discharge it into the underground storage tank(s) 72. The refilling pump 75 (originally designed only to refill drained air cooler sections) is now preferably also dimensioned to be able to feed condensate from the underground storage tank(s) 72 into the returning main line 68. The inventive method relates to operate the above power plant together with its cooling system in a way when steam power plant PFC operation is initiated via throttling or closing the condensate control valve 39, thus unused condensate increases the water level in the direct contact condenser hotwell 57, then the discharge control valve 73 opens and discharges water preferably from the returning main line 68 into the storage tank(s) 72 (located at or near the tower area) to set the level range required in the direct contact condenser hotwell 57 during the PFC period. When the water level in the feedwater tank 4 reaches the allowable minimum level or whenever the PFC (and SFC) periods by condensate throttling / stop are over, the operation based on condensate throttling/stop shall be terminated including preferably the following main steps:

- the discharge control valve 73 closes,

- the condensate control valve 39 and the steam extraction valves 11-14 open,

- the condensate recirculating valve 41 closes,

- the refilling pump(s) 75 feed condensate from the storage tank(s) 72 back to the direct contact condenser 56 via the returning main line 68 (in a quantity corresponding to that discharged previously),

- the condensate extraction pump 38 or the condensate booster pump 58 operates with full capacity

throughout reinstating the full condensate throttling/stop capability to be applied in a next round of PFC.

LIST OF REFERENCE NUMERALS

1 -3 feedwater heaters

4 feedwater tank (and heater/deaerator )

5-7 feedwater heaters

8 feedwater pump

9 boiler

9a superheater

9b reheater

11-14 steam extraction valves 21-27 steam extraction lines

31 turbine control valve

32 high pressure turbine section

33 intermediate pressure turbine section

34 low pressure turbine section

35 cooling water circulating pump

36 surface condenser

37 hotwell

38 condensate extraction pump

39 condensate control valve

41 condensate recirculating valve

42 make-up water valve

43 cold auxiliary condensate valve

44 warm auxiliary condensate valve

56 direct contact condenser

57 hotwell

58 condensate booster pump

65 cooling water circulating pump

66 recovery hydro turbine (connected to DC condenser)

67 forwarding main line

68 returning main line

70 cooling tower

71 air coolers (e.g. cooling deltas)

72 storage tank

73 discharge control valve

74 fine level control valve (for the normal operation)

75 refilling pump

76 refilling valve

77 reinstating valve

80 dry cooling system (Heller System)