WO2015149124A1

WO2015149124A1 - Use of stored heat energy in a combined cycle gas turbine power generating system

Info

Publication number: WO2015149124A1
Application number: PCT/AU2015/050141
Authority: WO
Inventors: Nicholas Jordan BAIN; Garry James Baddock; Peter LEMMICH; David John Reynolds; Paul Soo-Hock Khoo; Jun CHAO
Original assignee: Graphite Energy NV
Current assignee: Graphite Energy NV
Priority date: 2014-04-01
Filing date: 2015-03-31
Publication date: 2015-10-08
Anticipated expiration: 2016-10-01

Abstract

A combined cycle gas turbine power generating system, comprises: a gas turbine, a heat recovery steam generator; a steam turbine system; an energy storage system which stores energy in the form of heat energy; and a heat energy distribution system. A method of operating the combined cycle gas turbine power generating system includes: a) storing energy in the form of heat energy; and b) using the stored heat energy to heat components of the combined cycle gas turbine power generating system during periods when the combined cycle gas turbine power generating system is not operational and/or during start-up periods.

Description

USE OF STORED HEAT ENERGY IN A COMBINED CYCLE GAS TURBINE

POWER GENERATING SYSTEM

Introduction This application relates to start-up of fossil fuel generating plant and in particular describes a method of using stored energy to start-up fossil fuel plant that is used intermittently.

Background

The current pathways to achieving lower system-wide heat rates and carbon emissions are a combination of:

Increasing the penetration of renewable energy; and

Increasing the efficiency of the existing installed base of generation through replacement or repowering existing infrastructure with more efficient generation equipment.

It is recognized that the unprecedented increase in renewable power generation

(primarily solar and wind energy resources) is already having a significant impact on the economics of fossil fuel generation, in particular Combined Cycle Gas Turbine (CCGT) generation.

The primary issue is that renewables, whilst having a high installed cost, can generate power at close to zero marginal cost, when available. This means that on-grid renewables will always get dispatched first and off-grid renewables will displace on-grid demand. Solar is already dominating the daytime peak load, which is where generators have traditionally made most of their money. This means CCGTs are left to compete for the shoulder and off-peak markets, and to suffer from daily start-up and shut-down cycles.

Equipment manufacturers are responding by designing faster start-up CCGT plants or promoting combustion engine generation. Other solutions include chemical battery storage for bulk electricity load shifting. Whilst there are multiple new-build solutions, all with different cost-benefits, in-situ CCGTs are fast becoming uneconomic - they were generally designed for baseload operation but are increasingly being operated to pick up load in peak periods or when renewable sources go offline.

As solar pushes the CCGT off-line during the day, CCGT plant owners have the choice of running at a negative "spark spread" (the difference between market price and cost of production) or shutting down. When solar wanes at the end of the day and evening demand returns, the CCGT will be called back into service; incurring a new, slow and expensive start-up. Summary

According to a first aspect, a method is provided for operating a combined cycle gas turbine power generating system, comprising a gas turbine, a heat recovery steam generator and a steam turbine system, the method comprising:

a) storing energy in the form of heat energy; and

b) using the stored heat energy to heat components of the combined cycle gas turbine power generating system during periods when the combined cycle gas turbine power generating system is not operational and/or during start-up periods.

According to a second aspect, a combined cycle gas turbine power generating system, comprises:

a gas turbine,

a heat recovery steam generator;

a steam turbine system;

an energy storage system which stores energy in the form of heat energy; and a heat energy distribution system to distribute the stored heat energy components of the combined cycle gas turbine power generating system to heat the components of the combined cycle gas turbine power generating system during periods when the combined cycle gas turbine power generating system is not operational and/or during start-up periods.

The distribution system may connect the energy storage system to a steam drum of the heat recovery steam generator to heat the steam drum.

The distribution system may connect the energy storage system to the headers and harps of the heat recovery steam generator to heat the heat exchanger tubes, connecting headers and activate the selective catalytic reduction (SCR) system that reduces NOx emissions.

The heat storage system may include feed water stored in a feed water storage tank. The feed water may be electrically heated and the feed water storage tank may be insulated.

The distribution system may also connect the energy storage system to a turbine or turbines of the steam turbine system to heat the turbine or turbines and to maintain steam turbine gland seals to prevent ingress of oxygen into the turbine.

The distribution system may also connect the energy storage system to the gas turbine to warm the gas turbine and gas turbine fuel prior to gas turbine ignition and during start up. The distribution system may also connect the energy storage system to the condenser steam air ejectors to maintain condenser vacuum which keeps the steam bypass system operational.

The distribution system may connect the energy storage system to steam pipes which deliver steam from the heat recovery steam generator to the steam turbine system to heat the steam pipes.

The distribution system may connect the energy storage system to steam pipes which deliver steam from the heat recovery steam generator to a high pressure turbine of the steam turbine system, via steam tracing along the pipes to preheat the steam pipes.

The distribution system may also connect the energy storage system to steam pipes which deliver steam from the heat recovery steam generator to a high pressure turbine and/or an intermediate pressure turbine and/or a low pressure turbine of the steam turbine system, to deliver steam through the pipes to the high pressure turbine and/or the intermediate pressure turbine and/or the low pressure turbine thereby heating the pipes of the high pressure and/or the intermediate and/or low pressure turbines. The steam passed through the high pressure turbine, intermediate pressure turbine and/or low pressure turbine may also be used to operate the high pressure turbine, intermediate pressure turbine and/or low pressure turbine to generate electricity while the gas turbine and heat recovery steam generator are being brought on-line.

Electrical heaters may be located to heat the heat storage material, the heaters comprising resistive heating elements connected to an electrical supply to use electrical energy generated in excess to a current demand provided by a consumer load. The electrical supply may include a renewable energy source, such as a solar energy source. The electrical supply may also include a non-renewable source which is connected to supply energy during dips in demand or during periods where the non-renewable energy source is being shut down and are generating more energy than is required by the consumer load.

The body or bodies of heat storage material may comprise graphite enclosed in a gas tight housing. Radiative heaters may be positioned adjacent to each gas tight housing to heat the graphite. Tubes may be embedded in the graphite and extend through the gas tight housing, such that the tubes may carry a heat exchange fluid to extract heat from the graphite. The heat transfer fluid may be water/steam and the heat distribution system may comprise steam pipes connected to the tubes embedded in the graphite to deliver hot water and/or steam directly to the components to be heated.

The heat transfer fluid may also be air or any other fluid like supercritical C0₂, a refrigerant, heat transfer oil or molten salt. During the periods when the combined cycle gas turbine power generating system is not operational, the stored heat energy may be used to keep the components of the CCGT power plant at or close to operating conditions. Brief Description of the drawings

Embodiments of the invention will now be described by way of example with reference to the accompanying drawings in which:

Figure 1 shows a storage module for converting electricity to thermal energy and storing the thermal energy in graphite for later use;

Figure 2 shows a thermal energy storage panel used in the thermal energy storage module of Figure 1 shown in perspective.

Figure 3 shows the thermal energy storage panel of Figure 2 in plan (Figure 3a), elevation (Figure 3b) and end elevation (Figure 3 c);

Figure 4 shows a perspective view of a heat exchanger coil used in the panel of

Figure 2 & 3;

Figure 5 shows a partial perspective view of the heat exchanger coil of Figure 4 sitting on a base capping graphite plank and showing insertion of a graphite plank adjacent to the base capping plank (viewed from a non-insertion end);

Figure 6 shows a partial perspective view of the heat exchanger coil of figures 4 &

5 with a number of a graphite planks inserted viewed from a second (non-insertion) end;

Figure 7 shows a perspective view of the heat exchanger coil of figures 4, 5 & 6 fully embedded in graphite planks, with a top capping plank removed, viewed from a second (non-insertion) end;

Figure 8 shows the thermal energy storage panel of Figures 2 & 3 with a surface of the housing removed;

Figure 9 shows a cross-section of two of the planks seen in Figures 5, 6, 7 and 8 illustrating a half obround groove in which the heat exchanger tubing is contained;

Figure 10a and 10b shows a heater assembly used in the thermal energy storage module of Figure 1 ;

Figure 11 shows a heater which forms part of the heater assembly of Figure 10a and

10b;

Figure 12 schematically illustrates the electrical circuit used to operate the thermal energy storage module of Figure 1. Figure 13 Illustrates Process Flow Diagram of a conventional CCGT Power Plant showing tanks and vessels which may be used to store electrically generated thermal energy; and

Figure 14 Illustrates Process Flow Diagram of a conventional CCGT Power Plant with thermal energy storage modules for fast start-up, supplementing STG steam or maintaining system temperatures.

Detailed description Referring to the accompanying drawings, the example of a thermal energy storage module described below converts electrical energy to thermal energy that is then stored as sensible heat in graphite. The electrical energy is converted to thermal energy using electric resistance heating elements. The stored energy can then be extracted by passing a working fluid such as water through the graphite. The water can be heated anywhere from sub-saturated hot water through to superheated steam by varying the flowrate through the graphite. Consequently, the heated fluid can then be used in a variety of applications, ranging from power generation in a conventional Rankine cycle power plant to providing hot water or saturated steam for other processes. There are a number of potential applications for thermal energy storage modules in a conventional Combined Cycle Gas Turbine power plant. These include:

Facilitating fast start-up by maintaining system temperatures in between shut down and start-up or pre-heating the system prior to start up, and

Supplementing turbine steam for incremental electrical generation. The following terms abbreviations will be used in this Description:

COLD START: A power plant start-up following a period of inoperation of greater than 60 hours

FULL LOAD: The state of operation where the plant output is at rated capacity

HOT START: A power plant start-up following a period of inoperation of less than 12 hours

PARTIAL LOAD: The state of operation where the plant output is below rated capacity WARM START: A power plant start-up following a period of inoperation of between 12 and 60 hours

Referring to Figure 1, a thermal energy storage module 100 is illustrated. The thermal energy storage module 100 is housed in a housing 101 having the dimensions of a standard intermodal shipping container making the unit relatively easy to transport using conventional transportation equipment. The housing 101 would typically have an outer skin, which is not shown in Figure 1 to permit a view of internal components. Within the housing a plurality of discrete thermal energy storage panels 102 are alternated with heater assemblies 106 (described in greater detail below). Each thermal energy storage panel 102 has a metal shell containing a graphite body and embedded tubes for heat recovery also described in detail below.

The thermal energy storage panels 102 are suspended from mounting frames 105 to which they are bolted. The mounting frames 105 are in turn suspended from cross members 104 supported between upper rails 103 of the housing 101 of the thermal energy storage module 100.

The heater assemblies 106 between adjacent thermal energy storage panels 102 comprise a plurality of electric resistive heaters 107 producing radiant energy that is absorbed through the shells of the thermal energy storage panels 102 to heat the internal graphite bodies.

Thus the heaters 107 of the thermal energy storage module 100 may be connected to the electrical energy distribution grid or a renewable energy supply so when supply exceeds demand for energy the heaters 107 are energised and radiate heat towards the thermal energy storage panels 102 which absorb the heat in the graphite encased in each thermal energy storage panel 102 to store excess energy from the grid or produced by the renewable source for later use.

These resistive heaters also function as a load bank which assists in regulating grid frequency.

Each of the thermal energy storage panels 102 includes embedded tubes, which carry a heat transfer fluid and enable heat to be recovered from the thermal energy storage panels. Inlet tubes 113, 114 deliver heat transfer fluid to each thermal energy storage panel 102 from an inlet manifold 115, and after being heated, the heat transfer fluid is passed from each thermal energy storage panel 102 via outlet tubes 117, 118 connected to an outlet manifold 119.

When the demand for electrical energy exceeds supply, a heat transfer fluid is passed through the tubes embedded in the graphite to extract the stored heat for use to drive a power generating machine. Typically the heat transfer fluid will be water/steam, although other possibilities exist such as air, supercritical carbon dioxide, heat transfer fluids, refrigerants and molten salt.

A plurality of thermal energy storage modules 100 may be used in a system with different thermal energy storage modules being switched in to receive excess energy as the amount of excess energy increases. Similarly different thermal energy storage modules 100 may be brought on-line to permit recovery of stored energy as demand increases above the available supply of renewable energy.

The use of a plurality of thermal energy storage panels in the thermal energy storage module, of the embodiments described herein and the method of their operation allows the parameters of the thermal energy storage module to be constrained such that the possibility a graphite fire may be substantially reduced.

The graphite in each thermal energy storage panel may be encased in a gas tight high temperature stainless steel skin filled with an inert gas, such as argon gas. The condition of the inert gas may be continuously monitored and the module unit shut down when the condition of the inert gas in a thermal energy storage panel is lost. For example the pressure of the inert gas may be monitored and the module shut down if the pressure in one thermal energy storage panel drops below a predetermined level, or if while temperature is stable the pressure does not remain within predefined limits. The thermal energy storage panels may also include an oxygen sensor to monitor for presence of oxygen and the heating may be shut down if oxygen is detected in any significant amount.

Each thermal energy storage panel may have a plurality of temperature sensors (e.g. 6), such as thermocouples Tl-1 to T8-3, (as seen in Figure 12) to measure graphite temperature at multiple locations within the panel. The graphite is heated to a maximum operating temperature (e.g. 650 °C), which is well below the temperature at which a graphite fire can be initiated or sustained.

The heating elements in the thermal energy storage module may be sized to reach the maximum operating temperature in a set duration (for example 4 hours). Thermal energy input is preferably stopped when the average graphite temperature reaches the maximum operating temperature (e.g. 650°C). In the event that this safety mechanism fails, heating elements of the heater 107 are designed to fail if their ambient temperature (in the middle of the heater elements) reaches 1000 °C.

The thermal energy storage module may comprise 8 thermal energy storage panels each containing 2200kg of graphite. Each thermal energy storage panel is separated from adjacent energy storage panels and each energy storage panel is encased by a high temperature steel skin. This separates the graphite mass into small sub-units, which are each well below the critical mass required for sustaining a graphite fire.

The thermal energy storage module is designed to extract heat efficiently through the embedded heat exchanger tubes in the graphite of each thermal energy storage panels. The current embodiment of the thermal energy storage module has been rated to extract 3.6MWh of thermal energy over 4 hours however it will be appreciated that these design parameters may be modified without departing form the fundamental design principles discussed herein. In the event of graphite temperature exceeding the maximum average operating temperature (i.e. of 650°C in this example) the heating elements may be shut off. In the improbable event that this safety mechanism fails, the elements may also be capable of being manually shut off and the heat may be extracted out of the graphite through a working fluid such as feed water or steam fed to the units. The working fluid could also be air, supercritical C0₂, heat transfer fluid, refrigerant or molten salt.

The present thermal energy storage module uses purely sensible heat storage in an inert material.

In a preferred embodiment the heaters would be rated at between 15kW to 40kW and the total heating capacity could range from 750kW to l,500kW, however this depends on the design time for charging the system and may be varied for particular applications (the shorter charge time the larger the heater capacity required). The heaters are typically powered by 3 phase power with control by electronic control devices such as thyristors but may have simple ON / OFF control. In the illustrated embodiment each heater assembly 106 comprises a column of 5 heaters 107 which are divided into 7 groups of 5 heaters. The heaters could be connected in different configurations for instance in delta or star configuration.

Thyristor control provides variable power to the heaters 107 of the heater assemblies 106, with each heater 107 connected to one thyristor or a group of heaters 106 connected to one thyristors (TY1-TY7 in Figure 12) or all of the heaters 107 connected to one thyristor. The thyristors TY1-7 may for example allow power to trickle into thermal energy storage panels 102 as they approach the maximum design temperature. A central control system may provide commands to a local controller to operate the thyristors to turn heaters on or off or to heat and a reduced level.

Apart for temperature sensors in the thermal energy storage panels there may be one or more temperature sensors per heating element, such as thermocouples HE1-HE35, linked to its temperature controller to ensure the element does not overheat shortening its useful life.

Typically the heaters may be designed for 415 Volt 50 Amp 50 Hz per phase AC operation, but may vary from country to country and site to site based on specifications of the available power supply. For example the supply may not be 3 phase, may operate at a different current and voltage and may be a different frequency such as 60Hz and could be in DC current as opposed to AC.

At the plant storage system level thermal energy storage modules may be connected in 'trains' where a 'train' consists of thermal energy storage modules connected in series and/or in parallel depending on the steam conditions required for that plant (see Figure 14). In Figure 2 an example of the outer housing of a thermal energy storage panel 102 is illustrated in perspective view. The panel of Figure 2 is also illustrated in Figure 3 in plan (Figure 3a), elevation (Figure 3b), and end elevation (Figure 3c) views. The thermal energy storage panel housing comprises two large substantially flat parallel side walls 212, 213 bounded by a bottom wall 214, end walls 215, 216 and a top wall 217 to form a closed container. In use the panel 102 will typically be oriented vertically with the bottom wall 214 typically located at a lower end of the panel. With reference to Figure 2 and Figure 3a, b, & c, in one form the housing has dimensions of 2200mm (C) x 1800mm (B) x 400mm (A) (see Figure 3), however these dimensions may vary to optimize usage of graphite cut from standard dimension blocks and to optimize packing of complete thermal energy storage panels into containers of different sizes.

The bottom wall 214 of the housing may be integrally formed with the two side walls 212, 213 by bending a single piece of wall material into a "U" shape in which the base transitions into each of the side walls via a curved bend of radius R which in the present example is in the range of 50 to 180 mm and nominally 80 mm. The wall material is preferably a sheet steel material capable of retaining structural integrity to support the enclosed graphite core, the heat exchanger and any heat exchange fluid contained therein at elevated temperatures of at least 1000°C.

The walls of the housings in Figures 2 and 3 are preferably fabricated from stainless steel (316/304) or 253MA austenitic stainless steel (or any suitable high temperature thermally conductive material such as 800H austenitic steel or alloys such as Inconel) finished to mill finish class 2B. The surfaces 212, 213, 214, 215, 216 & 217 of the thermal energy storage panels 102 may have a natural finish to the stainless steel material (specific emissivity 0.7) or a polished surface (specific emissivity 0.2 - 0.3), or may be provided with another suitable surface coating or treatment (specific emissivity in the range of 0.3 - 0.8). The surfaces 212, 213, 214, 215, 216 & 217 may also be coated with a robust high temperature heat absorbing (e.g. black - specific absorptivity in the range of 0.8 - 1.0, preferably 0.90 - 1.0) paint, surface treatment or other suitable coating.

Mounting flanges 121 are provided extending from the tops of the end walls 215, 216 and include respective mounting holes 223. The flanges 121 are used to suspend the panel 102 from the mounting frame 105 by bolting them to the mounting frame via the mounting holes 223. Each flange may comprise an extension of one of the end walls 215, 216 beyond the respective side wall 213 to which it is joined (i.e. the flange may be cut from the same piece of sheet material as the end walls 215, 216 from which they extend). By suspending the thermal energy storage panel from the flanges 121 rather than supporting it from below, the resulting tension in the side walls due to gravity of the graphite core acting on the housing allows them to resist buckling to maintain good thermal communication with the graphite core. The curved shape of the housing where the side walls 115, 116 join the bottom wall 114 through a bend also tends to keep the metal walls pressed against the graphite core.

Vents 251 are provided in the top wall 217 of the housing to allow venting during welding together of the housing walls. These holes may be plugged (e.g. by welding after the panel walls are joined), or they may be used to accommodate sealed cable ports through the wall to pass instrumentation cables such as thermocouple wires into the housing, as fill ports to provide an argon blanket to the graphite core, to accommodate a filling nozzle to fill the void space and/ or an internal reservoir with graphite powder or other thermally conductive media, or to accommodate a connection to an external reservoir to maintain the level of such materials when the graphite core and housing expand and contract during thermal cycling. In the illustrated embodiment, one of the holes 251 is used to accommodate sealed cable port 161 through the wall to pass instrumentation cables such as thermocouple wires into the housing. The cable port 161 is also used as a fill port to provide the argon blanket to the graphite core. A second hole 251 is used to accommodate a filling nozzle 163 to fill the void space and/ or an internal reservoir with the graphite powder or other thermally conductive media.

Referring to Figure 4, a heat exchanger 420 is shown in perspective. The heat exchanger 420 is embedded in a graphite core as seen in Figures 5, 6 & 7. The heat exchanger 420 comprises heat exchanger tubing 425, 426, 427, 438, 439, 440 and first and second heat exchanger inlet 113, 114 and first and second heat exchanger outlet 117, 118. The first and second heat exchanger inlet 113, 114 and first and second heat exchanger 117, 118 are interchangeable as inlet or outlet depending on the direction in which it is desired to flow the heat exchange fluid through the heat exchanger in a particular application. The heat exchanger inlets 113, 114 terminate straight tube portions 440 which form part of a first serpentine shaped tube portion 425 comprising sequential "U" shaped sections 428. The first serpentine shaped tube portions 425, of which there are two in parallel, are joined with welded joins 437 to a plurality of intermediate serpentine shaped tube portions 426, similarly joined together by welded joins 437. Final serpentine shaped tube portions 426 are joined to final serpentine shaped tube portions 427 by further welded joins 437. The final serpentine shaped tube portions 427 each terminate in outlet sections 438 & 439 which extend to the outlets 117 & 118 respectively.

The number of "U" shaped sections 428 provided in the serpentine portions 425, 426, 427 can vary depending on the application. For example for low flow rates with long discharge durations, the fewer the number of "U" shaped sections 428 may be required and conversely for high flow rates with short discharge durations more "U" shaped sections 428 may be required.

The heat exchanger tubes may be made, for example, from 253MA austenitic stainless steel (or any suitable high temperature thermally conductive material such as 800H austenitic steel or alloys such as Inconel), and may have a nominal outside diameter in the range of for example 26.67mm to 42.16mm. In the present embodiment the nominal outside diameter is 33.4mm but the outside diameter may vary to be greater or smaller than this depending on the particular circumstances of the application.

The heat exchanger tubing 426, 439, 440, and associated inlet tubes 113, 114 and first and second heat exchanger outlet tubes 117, 118 are preferably formed with at least some sections of the tube assembly taking a coiled or serpentine form suitable for compression (like a spring) during assembly (e.g. the serpentine portions 425, 426, 427 and the outlet sections 438, 439), such that when the housing 102 expands due to thermal expansion, the resulting stresses from the movement of the pipe configuration does not exceed the mechanical properties of the pipe material.

Referring to Figures 4, 5, 6 and 7, the heat exchanger inlets 113 & 114 extend through the ends of grooves 511 in a bottom graphite capping plank 509. The "U" shaped bends 428 in the tube portions 426 are accommodated in recesses 513 in the ends of the graphite planks 512. A hole 522 is also provided in the graphite planks 512 to permit the insertion of a locating tube (not shown) to maintain the location of the graphite planks after assembly. Referring to Figure 8, the heat exchanger outlet tubes 117 & 118 extend through openings 252, & 253 in the top wall 117 of the housing 102 and the heat exchanger inlet tubes 113 & 114 extend through openings 255, & 254 in the bottom of the end wall 216 of the housing 102. The tubing portions 425, 426, 427 are able to move to accommodate expansion of the heat exchanger tubing in use, without exceeding the material limits of the tubing.

The heat exchanger inlets 113, 114 terminate straight tube portions 440 which join a first "U" shaped tube portion 425. A plurality of "U" shaped tube portions 426 are then joined, terminating with a join 437 to a further straight tube portion 438 and 439 which extends to the outlets 117, 118.

The housing is sealed around the heat exchanger inlet tubes 113 & 114 and outlet tubes 117 & 118 where they exit the housing through the holes 252, 253, 255 & 254 such that air cannot enter the housing after it is sealed. The plurality of openings 251 in the top wall 217 of the housing (as seen in Figure 8) act as vents during welding together of the wall panels. These vents may be sealed by welding after the rest of the panel has been welded together or they may be used as sealed cable ports for sensors such as thermocouples used to monitor conditions inside the panel in operation, as fill and purge ports to provide argon blanket to graphite core or as filling nozzle to fill void space with graphite powder or other thermally conductive media.

After the heat exchanger is fabricated, pre-shaped planks of graphite 509, 512, are positioned to encompass most of the heat exchanger tubes. Referring to Figure 5, first a lower capping plank 509 is positioned beneath the lowest tubes 440 which extend to the inlets 113 &114.

The lower capping plank 509 is grooved 511 on one (upper) surface with the grooves having a semicircular (or preferably obround) cross-section conforming to the shape and radius of the lowest tube sections 440 of the heat exchanger. The lower edges 506 of the lower capping plank 509, between the face opposite the grooved surface (i.e. the downward facing surface in Figures 5, 6 & 7) have a radius corresponding with the transition 271 between the side walls 212, 213 and the base wall 214 of the housing (see Figure 8). The edges 506 may have a radius in the range of 50-150 mm and in the proposed embodiment will have a radius of 80mm.

Referring to Figures 5, 6, 7 & 9, the bulk of the graphite planks 512 are positioned between the rows of tubes in the tube portions 425, 426, 427. The graphite planks 512 each include two opposite surfaces in which the semicircular (or preferably semi-obround) grooves 511, 516 are formed, conforming to the shape and radius of the tubes of tube portions 425, 426, 427. When semi-obround grooves are used they are elongated in the vertical direction (i.e. two grooves abut to form an obround cross section with a vertical major axis) to accommodate expansion of the tube assembly in the vertical direction (as viewed in Figure 7). Referring to Figure 9, a partial cross section of two abutting planks 512 shows two pairs of aligned semi-obround grooves (511, 516) encompassing a pair of tubes 426.

Referring to Figure 8, after the remaining graphite planks 512 are in position a void 802 will remain above planks to accommodate the tube sections 438 & 439. A volume of graphite powder 801 is deposited over the upper tube sections 438 & 439 in the void 802 to accommodate expansion and contraction of the housing and the heat exchanger 420 as the temperature of the assembly changes. The graphite powder may not completely fill the void 802 leaving a small space above the graphite powder 801.

Preferably the abutting surfaces of the graphite planks of Figures 5, 6 & 7 will have a surface finish which is N8 or better (ISO 1302). Such that when assembled between rows of straight tube portions adjacent pairs of the planks encompass and closely conform to the respective straight tube portions and first connecting tube portions at the internal working temperature of the panel, which is up to 800°C, the grooves are made approximately 1.6% bigger than the nominal outside diameter of the tubes with a tolerance of approximately +0.00/- 1.00%. For example, when the heat exchanger tubes are made from 253MA austenitic stainless steel (any suitable high temperature thermally conductive material such as 800H austenitic steel or alloys such as Inconel) and have a nominal outside diameter of 33.4mm, the grooves will preferably be 33.9mm (+0.00/-0.25mm) in diameter. Alternatively, when the heat exchanger tubes are made from the same or similar material and have a nominal outside diameter of 26.67mm, the grooves will preferably be 27.1mm (+0.00/-0.25mm) in diameter and when the heat exchanger tubes have a nominal outside diameter of 42.16mm, the grooves will preferably be 42.9 (+0.00/-0.25mm) in diameter. To achieve a high contact surface without excessive expense, the surface of the graphite within the grooves will preferably have a surface finish which is N7 or better (ISO 1302). By maximising the contact of the graphite with the surface of the grooves by designing the grooves to be sized appropriately for the tube diameter at the working temperature and by providing appropriate surface finish, the operation of the heat exchanger within the graphite is enhanced.

The graphite planks 509, 512, are assembled to encompass the heat exchanger 420, in the open housing, and the locating tube is inserted into the hole 522 extending through all of the planks to maintain alignment. The locating tube may engage a locating pin projecting from the base of the housing (not shown) to locate the graphite core 509, 512, within the housing. The housing is then welded closed, including sealing the openings 255, 254, 252, 253 through which the inlet tubes 113 & 114 and outlet tubes 117 & 118 pass through the housing, to form the finished panel 102 (see Figures 3 & 8). The vent holes 251 may also be sealed either by welding or by inserting sealing plugs or a port fitting that allows sealed passage of transducer cables such as thermocouple wires into the interior of the panel. The vent holes 251 might also be fitted with port fittings to be used as fill ports to provide argon blanket to graphite core or as filling nozzles to fill void space 802 with graphite powder or other thermally conductive media.

Because the graphite planks extend to the ends of the housing and almost fully occupy the space within the housing, the load of the graphite is spread evenly across the bottom wall 214 of the housing, allowing thinner material to be used. Also by maximizing the area of graphite in contact with the walls and consequentially minimizing void space, the heat transfer into the graphite by conduction may be maximized. Minimizing void space also minimizes the amount of trapped air that is available to react with the graphite when the panel is heated to it operating temperature. In the present embodiment the volume of void spaces within the housing not occupied by graphite or tubing is generally in the range of 4- 10% and typically 5-7% of the internal volume of the housing (at the working temperature). Correspondingly the side panel of the housing, which is the irradiated surface of the panel when in use, is generally backed by the graphite core over all but 1-5 % of its area and typically 2-3% (at the working temperature) in the preferred embodiment.

In the top wall of the panels, openings 251 allow expansion of the internal air during manufacture and may be welded closed or used as ports. One of the openings 251 is shown with a filling nozzle 163 attached to permit filling of void spaces with graphite powder (refer to description of Figure 8 below).

Figure 8 shows a thermal energy storage panel 102 with one side wall removed showing the graphite planks 509, 512, forming the graphite core. Voids will exist between the graphite planks and the walls of the housing (e.g. between the planks 509, 512, visible in Figure 8 and the vertical walls 212, 213, 215, 216, including the wall 213 which has been removed). A larger void 802 forms a reservoir between the top of graphite core and the top of the housing. The reservoir 802 and the voids in this case are at least partly filled with graphite powder 801. The graphite powder 801 enhances heat transfer between walls of the housing and the graphite core. A filling nozzle 163 is in communication with the reservoir 802 to enable filling of the voids in the housing and topping up of the reservoir 802. The reservoir 802 stores additional graphite powder which prevents spaces opening up when expansion and contraction of the housing and core occur during thermal cycling. This arrangement may be employed in any of the previously described embodiments

Referring to Figures 10a & 10b, side and rear views are illustrated of one of the heater assemblies 106, used in the thermal energy storage module of Figure 1. The rear view is shown with a rear mounting panel 1002 removed. The heater assembly comprises a plurality of heaters 107 mounted through a front mounting panel 1001 and supported by support rails 1011 which are supported by the rear mounting panel 1002. Figure 11 is a perspective view of one of the heaters 107 seen in the heater assembly 106 of Figure 10a. The heaters 107 comprise Thermal Tubular-Calrod™ heating elements 1003, or equivalent, which are manufactured with a resistance coil of nickel-chrome wire centrally located within a metal sheath tube. Terminal pins are fusion welded to each end of the resistance coil. These terminal pins form the cold zone 1113 of the heating element 1003, seen in Figure 11. The resistance coil assembly is stretched within the tube and filled with a magnesium oxide powder, which electrically insulates the assembly from the outer sheath of the element. The magnesium oxide powder has excellent heat transfer properties and when combined with an evenly stretched resistance coil, a uniform heat is achieved along the length of the heating element 1003. Once filled, the heating element 1003 is then roll compacted, which compresses the magnesium oxide powder to a rock hard construction. This protects the resistance assembly from atmospheric corrosion and mechanical damage. The heating element 1003 is then trimmed at each end to expose the terminal pin. Silicone insulators are used to insulate the terminal pin from the outer sheath of the heating element 1003 and a terminal connection is fitted. The heating elements 1003 are then bent into "U" shapes and fitted into the assembly 107 in which the heater elements 1003 pass through a plurality of intermediate spacers 1004. Cold legs 1113 are provided at the terminal ends of the elements 1003 which pass through a mounting flange 1005

The heaters 107 are mounted in the thermal energy storage module 100 via the front mounting panel 1001 a top panel 1010 and the rear mounting panel 1002. The front panel 1001, the top panel 1010 and rear panel 1002 may be formed from a single folded sheet of high temperature plate steel. In the case of the front mounting panel 1001, tubes 1008 extend from the mounting panel and terminate in flanges 1009 to which mounting flanges 1005 of the heaters are bolted. The cold legs 1113 of the heater elements pass through the tubes 1008 such that the tubes are not heated excessively. Connection to the individual elements 1003 of the heaters is made to the heater element terminals 1007 mounted on the heating element mounting flange 1005. The thermal energy storage module 100 may include an internal cabling tray (not shown) and each of the heaters 107 (flanged heating element bundles (FHE's)) may be wired up with a cable looped at the end of the module to which an Electrical Controller (ECB) 1200 is mounted, inside a removable hatch at the end of the module.

Referring to Figure 12, the example thermal energy storage module 100 illustrated in Figure 1 may comprise:

i. 8 thermal energy storage panels each containing 2200 kg of graphite;

ii. 7 vertical columns of FHEs 107;

iii. Each vertical column of heaters Comprises 5 FHE's 107;

iv. Each FHE 107 is rated at 30kW (3 phase 415 V, 50 Hz) providing 150KW per column or 1.05 MW per thermal energy storage module 100) heating both sides of Panels 102 (except the end panels which are heated on one side only);

v. All FHE 107 connections are made on one side of the Module 100 and are spaced 200mm inside the insulated face panel (not illustrated) of the module;

vi. Each thermal energy storage panel 102 has 3 thermocouples, (or a total of 24

thermocouples per thermal energy storage module 100: TPl-1 to TP8-3);

vii. Each FHE 107 has a single thermocouple located within the bundle of heater

elements 1003 (HE1 to HE35);

viii. The thermal energy storage module 100 also includes at least one inlet manifold thermocouple Til, and at least one outlet manifold thermocouple TQI ; ix. Each thermal energy storage panel 102 has a sensor for measuring the condition of the inert gas (e.g. argon) pressure within the thermal energy storage panel (e.g. 8 pressure transmitters per module: PT1-PT8) and optionally one oxygen sensor (OT1-OT8);

The Electrical Controller (ECB) 1200 may be attached to an end or the side of the thermal energy storage module 100 and may comprise:

i. A weatherproof Electrical Control Box or housing 1202 having for example

dimensions of 2.43m W x 2.89m H (max) x any suitable depth. If the height of the housing is less than the height of the thermal energy storage module 100, an awning may be installed above the housing for shade;

ii. The ECB will preferably be suitably Ingress Protection (IP) rated;

iii. A main manual isolator Contactor S 1 may be provided for the thermal energy storage module to permit total electrical isolation of all of the heaters 106 of the module 100.

iv. A manual isolator S2-8 may be provided for each column of FHE's 107;

v. A Programmable Logic Controller (PLC) 1201 programmed to:

a. Monitor the thermocouples Tl-1 to T8-3;

b. The thermocouples HE1 to HE35;

c. The thermocouples Til and Tol; and

d. The pressure transmitters PT1 to PT8;

e. Control power to each column of FHEs (or each FHE) by controlling

thyristors TY1-7 (or TY 1-35) which control power to the heaters;

f. Provide sequence control for the switching of the FHEs to avoid switching multiple heaters simultaneously.

g. Provide signal outputs 1203 and inputs 1204 for transmission to and from system level controllers (DCS) and displays providing control functions and indicating measured and calculated parameters such as:

• Module Average Graphite Temperature

• Module Max Graphite Temperature (which thermocouple on which Panel)

• Module Min Graphite Temperature (which thermocouple on which Panel)

• Module State of Charge %

• Module State of Thermal Charge kWh_t

• Each FHE status: offline, active, faulty

• Module Charge Current and Power • Inert gas (e.g. argon) Pressure PI to P8

• Inlet manifold and outlet manifold temperature

• System generated commands to start or stop heating

vi. A local display to display the outputs from PLC;

COMBINED CYCLE GAS TURBINE (CCGT) POWER PLANTS

Referring to Figure 13, an example of a CCGT system 1301 is illustrated comprising a Gas Turbine system 1302 and a Steam Turbine System 1303. In the Gas Turbine System, 1302, air 1304 is fed to a compressor 1305 driven by a Gas Turbine 1308. Fuel 1306 and the compressed air 1318 are fed to a combustion chamber 1307 and the hot gas 1319 produced by the combustion chamber 1307 is used to drive the Gas Turbine 1308. The Gas Turbine then drives a Generator 1309.

The hot gas exhaust 1311 from the Gas Turbine 1308 is then passed to a Heat Recovery Steam Generator (HRSG) 1312 where the hot gas 1311 is used to heat water and steam in a series of heat exchangers before being exhausted through a stack 1326. A first Heat exchanger 1321 of the HRSG 1312 is used to heat steam 1313 recovered from a High Pressure Steam Turbine 1351 to produce superheated steam 1314 which tempered with spray water 1316 in a de- superheater 1315 and the tempered steam 1317 is returned to drive an Intermediate Pressure Steam Turbine 1352 via a Pressure Reduction Valve 1355. The High Pressure Steam Turbine 1351 together with the Intermediate Pressure Steam Turbine 1352 and a Low Pressure Steam Turbine 1353 drive a generator 1354.

Three further heat exchangers 1322, 1323 & 1324 connected in series with a steam drum 1325 receive water 1331 to produce steam 1332, which is then which tempered with spray water 1333 in a de- superheater 1334 and the tempered steam 1335 is used to drive the High Pressure Steam Turbine 1351. Steam 1356 that has passed through the Intermediate Pressure Steam Turbine 1352 is then passed through the Low Pressure Steam Turbine 1353.

Low Pressure Steam 1336 that has passed through the Low Pressure Turbine 1353 is cooled in an air-cooled condenser 1337 to produce a condensate 1338 which is pumped by a condensate lift pump 1339 to a deaerator 1341. From the deaerator 1341, the water 1331 is again pumped to the heat exchanger 1322 by the HP Feed Pump 1343.

Top-up feed water 1342 is also fed to the condensate lift pump when required to increase the water level in the steam drum 1325. The Top up feed water 1342 may be delivered from a raw water storage tank 1344 via a water treatment plant 1345 and a treated water storage tank 1346. The hot gas 1311 which is used to heat water and steam in the HRSG 1312 is exhausted through the stack 1326. A stack damper 1327 in the form of a shut off flap may be fitted to the stack 1326. The stack damper 1327 is closed during shut down to keep the HRSG 1312 warm.

It will be appreciated that to start this CCGT system 1301 from cold is a lengthy process as first the Gas Turbine 1308 and gas fuel is warmed up and brought on line and the SCR activated, then the HRSG 1312 is brought up to operational temperature slowly with the Gas Turbine exhaust gasses 1311 and then the three steam turbine stages 1351, 1352 & 1353 are heated slowly to operating temperature and brought up to speed as the steam from the HRSG 1312 comes up to operating temperature and pressure. Steam generated from the HRSG is used to establish condenser vacuum and steam turbine gland seals then used for steam turbine bowl and rotor warming and stabilizing water chemistry before steam from the HRSG's is injected to the steam turbine. This process can be sped up if the various parts of the CCGT system can be kept at or near operating conditions during shut down or preheated prior to gas turbine start-up.

FACILITATING FAST START-UP OF A COMBINED CYCLE GAS TURBINE (CCGT)

Referring to Figure 14, the Thermal Energy Storage System described above with reference to Figures 1 to 12 can be used to facilitate faster start-up of conventional CCGT power plants such as that described with reference to Figure 13. The heat stored in the Thermal Energy Storage System can be used to keep warm or pre-heat the Heat Recovery Steam Generator (HRSG) 1312, steam piping and the steam turbines 1351, 1352 & 1353 - roles that would ordinarily be carried out as part of the start-up process.

In the arrangement illustrated in Figure 14, the Thermal Energy Storage System

1401 includes three heat storage sections designated for use as Pre-Heater Modules 1402, Evaporator Modules 1403 and Superheater Modules 1404. In each case the heat storage sections might comprise one or more thermal energy storage modules 100 as described with reference to Figure 1, depending on the size of the plant. Alternatively one or more of the storage sections 1402, 1403, 1404 might comprise only a subset of the panels 102 in a thermal storage module 100 if the plant is small. For the purpose of this description it will be assumed that each section 1402, 1403, 1404 comprises one or more thermal storage modules 100.

The Thermal Storage Modules 100 are electrically heated. The power used to heat the Thermal Storage Modules 100 will preferably be excess power in periods of over supply such as during periods where renewable (e.g. solar) energy exceeds demand or power generated by fossil fuel plant exceeds demand during troughs in demand or periods of reduced demand prior to or during shut down.

SUPPLEMENTING IP TURBINE STEAM

Thermal Energy Storage System 1401 is capable of producing steam at conditions suitable for admission to the High Pressure (HP) or Intermediate Pressure (IP) turbine in conventional CCGT power plants. In Figure 14, a second outlet from the deaerator 1341 feeds water 1410 from the deaerator 1341 through the IP feed pump 1411 into the pre- heater modules 1402. Hot water 1412 from the pre -heater modules 1402 is then passed through the evaporator modules 1403 to generate steam 1413 and the steam is passed through the superheater modules 1404 to generate superheated steam 1414. The superheated steam 1414 is tempered with spray water 1415 in a desuperheater 1416 and the resultant tempered steam is used for keeping the system hot or pre -heating the system prior to start-up of the CCGT plant.

MAINTAINING SYSTEM TEMPERATURES

The stored energy in the Thermal Energy Storage System 1401 can be used to maintain system temperatures in the CCGT power plant during short or medium term shutdowns. This is another way of facilitating fast start-ups. During shut-down, no steam is available from the CCGT power plant. Steam can be raised in the Thermal Energy Storage System 1401 and passed through critical elements of the power plant to maintain temperatures. Such elements might include the HRSG 1312 (particularly the steam drum 1325), the steam turbine 1351, 1352, 1353 and/or steam piping which normally supplies steam 1317 & 1335 to the turbines.

Figure 14 shows a typical CCGT power plant 1302, 1303 incorporating the Thermal

Energy Storage System 1401 for thermal energy storage from electrical energy. The dashed line 1421 represents the piping distributing steam for heating the HRSG headers, harps, drums 1325 and for activating the SCR. The dashed line 1422 represents the piping distributing steam or hot water to heat the fuel gas of the gas turbine. The dashed line 1423 represents the steam lines to the HP steam turbine 1351 respectively to maintain steam turbine gland seals and HP rotor/bowl temperatures. The steam line 1424 from the Thermal Energy Storage System 1401 to the IP steam turbine 1352 represents piping required for maintaining IP rotor/bowl temperatures and supplementing IP turbine steam for incremental power generation.

CCGT power plants are comprised of large quantities of steel to contain the working fluid (ie steam or water). This mass of steel is in the form of piping and tubing, pressure vessels, rotating equipment, tanks and so on. When the plant is in operation, the steel will be more or less at the same temperature as the fluid within. However, when the plant is not in operation, much of this steel will cool to some extent, depending on the duration of the outage. Once the plant recommences operation, the cooled steel will extract energy from the fluid within until it once again reaches operating temperature. The energy required to do this may be considered a form of parasitic loss. However, when the steel is below operating temperature it has the capacity to store heat. Adding heat to the steel will raise the temperature. Once the plant goes into operation, the parasitic load that would normally be required to warm the steel will not be required since the steel is already at operating temperature. This has the effect of making more steam available for power generation and consequently the energy stored in the steel is recovered through this increase in energy generated. Items of a typical CCGT power plant that are capable of storing heat in this way include steam piping, steam turbine and HRSG (particularly the steam drums). Piping can be heated using either electrical heat tracing or steam heat tracing. Electrical heat tracing converts electrical energy into thermal energy using electric resistance heating elements. Steam tracing requires steam generated either by an electric steam generator (boiler) or by an electrically heated thermal energy storage device such as the Thermal Energy Storage System 1401. Electric resistance heating would not generally be considered suitable for providing heat to the HRSG due to the high temperatures the elements would be subjected to and/or the modifications that would be required to the steam drum to install internal heating elements. However, steam can be introduced to the drum to provide the heat to be stored through existing piping on the steam drums. Steam can be used to heat the steam supply and return piping.

Water tanks or reservoirs can be found at a number of points in a conventional CCGT power plant. For example the steam drum 1325, deaerator 1341 and condenser 1337. There may also be a number of storage tanks on a given site for raw water 1344 and treated water 1346 (see Figure 13). In the case of the deaerator 1341 and steam druml325, when the plant is off line for a short period, it may be desirable to maintain the operating temperature in these vessels, so that the plant may be brought on line more rapidly by avoiding the need to heat the fluid in these vessels back up to operating temperature. This is a potential form of energy storage in the same way as pipe preheating is, as described in the previous section. The heat stored in these vessels is recovered by the increase in energy generated due to more steam being available during the start-up period. Other tanks on site also provide opportunities to store energy. By heating the fluid in these tanks, the energy required for preheating is reduced, thereby increasing the amount of energy available to generate steam and consequently electrical energy. OTHER FORMS OF SENSIBLE HEAT STORAGE

Whilst the Thermal Energy Storage System 100, 1401 described herein is a form of sensible heat storage, there are other technologies which could be employed in a similar way. Concrete, for example, is an alternative to graphite as a solid thermal storage medium, while molten salts are examples of liquid thermal storage media. Both solid and liquid thermal storage media may be heated by converting electrical energy into thermal energy using electric resistance heaters. Sensible heat storage media include:

Concrete

Rock beds

Synthetic oils

Molten Salts

Aquifers

Solar ponds

Table 1

1. Based on Therminol VP-1 (diphenyl biphenyl oxide).

2. Based on 60% NaN03 40% KN03 mixture. Table 2

* Denotes "Not Suitable"

Notes: Comparisons based on values at elevated temperatures >400°C where possible.

Tables 1 and 2 compare a number of properties of various materials that have been proposed for sensible heat storage.

All the above media will absorb and store heat to varying degrees. The heat can be extracted from the media by passing a heat transfer fluid through or around the media, and then making use of the heated fluid. The amount of energy that can be stored by a sensible heat medium is proportional to the difference between initial and final temperature, mass of medium and the heat capacity of the medium. The rate at which heat can be extracted is proportional to the thermal conductivity at the operating temperature and the heat transfer co-efficient between that material and the heat exchanger tubes. Each medium has relative advantages and disadvantages. For example, water has a relatively high heat capacity but at low pressures is limited to relatively low temperatures. Rock, on the other hand, has a relatively low heat capacity but this is offset by the large temperature changes the rock will allow but with low thermal conductivity. CCGT POWER PLANT START-UP SEQUENCE

A typical start-up sequence for a CCGT power plant consists of the following steps: Readiness checks Purge

Gas Turbine (GT) ignition and speed ramp-up to synchronization speed

GT synchronisation

GT load ramp-up to full load

HRSG / Steam Turbine (ST) warming

ST speed ramp-up to synchronization speed

ST synchronization

ST load ramp-up to full load READINESS CHECKS

Readiness checks involve checking that all prerequisite conditions are in place before starting the GT.

PURGE

The HRSG 1312 and Exhaust duct is purged with air prior to firing the GT in order to eliminate the possibility of igniting any remnant explosive fuel / air mixture. A typical purge requires five volume changes of air, and the duration varies from plant to plant depending on the volume of the ducting, HRSG 1312 and exhaust stack 1326. For a typical CCGT plant this takes from 10 to 20 minutes. During this step the GT shaft is rotated at an intermediate speed by a starter motor to force air through the HRSG.

NFPA 85, Boiler and Combustion Systems Hazards Code allows a credit on purge time if purging is conducted at the end of the previous run of the GT. If the conditions for the credit are met, up to 20 minutes can be deducted from the purge time that would normally be required. In the following discussions, it is assumed that this credit is applicable, and that the credit entirely negates the requirement for purging at start-up.

GT IGNITION AND SPEED RAMP-UP TO SYNCHRONISATION SPEED

Once purging (if required) has been completed, the GT is brought up to ignition speed and ignited. If purging was not conducted, the GT is brought up to ignition speed by the starter motor prior to ignition.

Once ignited, the GT speed is increased up to the speed required for synchronization. The exhaust gases commence heating the HRSG during this phase. The GT speed is held until steam from the HRSG is at SCR activation temperature as until the SCR is activated the NOX emissions are unable to be controlled. Once the SCR is activated and NOX control established, the GT can ramp to synchronisation speed. GT SYNCHRONISATION

Upon reaching synchronization speed, the generator is synchronized, the main circuit breaker is closed and the GT is partially loaded. GT LOAD RAMP-UP TO FULL LOAD

The GT load is gradually increased until full load is reached. During this phase, the HRSG 1312 will commence producing steam. The steam produced by the HRSG is used to establish condenser vacuum and ST gland seals then to warm the turbine 1351, 1352, 1353. The steam bypasses the ST and is directed to the condenser 1337 until both the ST warming has been completed and the steam produced by the HRSG reaches the conditions (pressure, temperature and flowrate) required by the ST. As the GT cycle is coupled to the steam cycle, at this stage the GT ramps slowly to partial load and is held there till the HRSG produces enough steam to generate condenser vacuum so that the HP steam is able to be bypassed through to the condenser, steam turbine gland seals are established and stable water chemistry is achieved.

HRSG / ST WARMING

HRSG and ST warming is achieved from heat generated by the GT exhaust coupling the GT cycle to the steam cycle. The HRSG consists of a large amount of heat transfer surfaces. These surfaces (usually tubing and cylindrical elements like drums and headers) are made of metal of varying thicknesses, and therefore need to be heat soaked slowly to bring them up to their normal operating temperatures with minimum damage. The rate of temperature increase in the metal surfaces is restricted in order to keep differential expansion stresses within acceptable limits. Usually the limiting components are the steam drums (HP, IP and or Low Pressure (LP)).

Depending on the particular plant in question, this rate of heating may be the limiting factor in reducing start-up times for a CCGT power plant. If the thicknesses are large it may be necessary to hold the GT at part load for a period of time to allow the surfaces to be brought up to operating temperature at an acceptable rate of temperature increase. For smaller plants this may not be an issue due to smaller component sizes and thicknesses. The time required also varies with the period that the plant has been out of operation.

The HRSG commences warming from the point of ignition of the GT due to the high exhaust gas temperatures. The warming continues as the GT undergoes load ramp- up. At some point during this phase, the HRSG will commence producing steam. It will take a period of time to increase the pressure, temperature and flowrate of the steam up to the conditions required for normal operation of the ST.

However, before the ST can be loaded, steam is required for a number of purposes. The ST gland seals require steam to function in advance of ST loading. The condenser vacuum is also established to enable steam from the HRSG to be bypassed to the condenser till it reaches minimum conditions acceptable by the ST.

Similarly to the HRSG, the steam turbine is heat soaked and gradually warmed to avoid thermal shock and the stresses involved therein. To achieve this, part of the steam being produced by the HRSG is passed through the ST while it is being rotated at low speed. The ST is warmed over a predetermined period of time, which places another limitation on start-up time of the steam cycle of a CCGT power plant. As with the HRSG, the time required for warming the ST varies depending on the period that the plant has been out of operation.

The remainder of the steam bypasses the ST and is directed to the condenser until the ST has been warmed, synchronized and can accept the steam.

ST SPEED RAMP-UP TO SYNCHRONISATION SPEED

Once sufficiently warmed, the ST speed is brought up to full speed. Once reached, the ST generator is then synchronized and loading of the ST commences.

ST SYNCHRONISATION

Once sufficiently warmed, the ST speed is brought up to full speed and the generator is synchronized. The ST is partially loaded. ST LOAD RAMP-UP TO FULL LOAD

Having been synchronized and partially loaded, the ST can then be brought up to full load at a regulated rate. The load on the ST is increased by increasing the steam flowrate through the ST. This is achieved by gradually decreasing the amount of steam bypassing the ST.

CONVENTIONAL START-UP SEQUENCE TIMING

The start-up procedure and timing for a typical plant consisting of two GE 7FA gas turbines, each connected to its own triple pressure reheat HRSG driving a single GE Dl l steam turbine, is discussed below by way of example. A triple pressure reheat steam turbine accepts steam from both HRSGs. The GTs each produce approximately 170 MW, while the GE Dl l ST produces approximately 160 MW delivering a total CCGT capacity of 500MW.

Being relatively large units, there are GT hold times for HRSG and ST warming required during the GT load ramp-up.

The start-up sequence and timing for three cases - hot start, warm start and cold start are considered below.

HOT START

If the CCGT power plant is to be started up after no more than an overnight shut- down (8 to 12 hours), the start-up is considered to be a "hot" start. The significance of this is that the HRSG and ST components are still relatively hot, since the duration of the shutdown is insufficient to allow significant cooling to have occurred. This, therefore, means that the period required for warming of the HRSG and ST during the start-up process is significantly less than that which would be required if starting the system from ambient temperature.

WARM START

If the CCGT power plant is to be started up after a shut-down of between 12 and 60 hours (for example, a start-up on a Monday morning following a shut-down on the preceding Friday afternoon), the start-up is considered to be a "warm" start. The significance of this is that the HRSG and ST components, although having cooled somewhat, are still relatively warm. This, therefore, means that the period required for warming of the HRSG and ST during the start-up process is significantly less than what would be required if starting the system from ambient temperature, although greater than would be required for a hot start.

COLD START

If the CCGT power plant is to be started up after a shut-down of greater than 60 hours, the start-up is considered to be a cold start. The significance of this is that the HRSG and ST components have cooled significantly. This, therefore, means that the period required for warming of the HRSG and ST during the start-up process is greater than would be required for either a hot or warm start.

CONVENTIONAL START-UP SEQUENCE TIMING

Table 3 below summarizes the cumulative time steps of the events in the start-up sequence for hot, warm and cold starts. Table 3

TYPICAL CUMULATIVE TIME STEPS DURING START-UP

1. It is assumed that the purging cycle was completed at the end of the previous cycle.

From the initiation of the GT start sequence for a hot start, it takes approximately 77 minutes before the CCGT power plant is at full load. From the initiation of the GT start sequence for a warm start, it takes approximately 145 minutes before the CCGT power plant is at full load. From the initiation of the GT start sequence for a cold start, it takes approximately 230 minutes before the CCGT power plant is at full load. Table 4: Summary of the duration of the events in the start-up sequence for hot, warm and cold starts.

TYPICAL DURATION of STEPS DURING START-UP 1,2

Warm

Hot Start Cold Start

Start

(Minutes) (Minutes)

(Minutes)

Readiness checks 1 1 1 Purge ³ 0 0 0 Lead GT ignition and ramp to FSNL 7 7 7 Condenser vacuum from GT ignition 7 22 32 SCR activated from GT ignition 18 32 42 Steam turbine seals from GT ignition 18 32 42 Lead GT synchronized from GT ignition 19 33 43 Lead GT slow ramp to part load to warm HRSG & ST 9 28 30 Hold part load warm HRSG, ST, steam piping, etc.

9 30 72 synchronize ST

Lead GT ramp from partial load to full load 17 17 17 ST load ramp to base load (from lead HRSG) 13 13 13 Lag GT ignition ramp to FSNL and synchronize 7 7 7 Lag GT ramp to part load, hold to warm lag HRSG 8 15 41 Lag GT ramp from part load to base load 6 6 6 Lag HRSG steam to ST from lag GT ignition 22 33 55 ST load ramp to full load 7 7 7 CCGT plant at full load (minutes from start) 77 145 230

Notes

1. Durations vary from plant to plant based on many factors including intended duty, equipment, environmental and climatic conditions and so on.

2. Some of the steps during the start-up process overlap, so the total time to full load for the plant is somewhat less than the sum of the durations listed in the table above.

3. In certain cases, purging can be conducted at the end of the preceding operating cycle, in which case it need not be performed at the start of the cycle. In the table above, it is assumed that no purge needs to be undertaken at the start of the operating cycle.

It should be noted that a number of the steps in the start-up sequence overlap, so that the total time to full load is somewhat less than the sum of the individual step durations ACCELERATED START-UP SEQUENCE TIMING USING STORED THERMAL ENERGY

Examination of the start-up sequence and timing for conventional start-ups (as shown in the figures below), be it hot, warm or cold, reveal opportunities to decrease the time required for the Combined Cycle Gas Turbine (CCGT) to achieve full load. This can be realized by supplying thermal energy from an external source to undertake the various warming functions in parallel with other start-up steps decoupling the GT cycle from the steam cycle.

The key areas that stored thermal energy can improve the time to full load for a conventional CCGT are:

Keeping the HRSG hot or pre -heating the HRSG prior to a start

Maintaining the ST gland seals operational and keeping the ST hot or pre-heating the ST prior to a start

Maintaining condenser vacuum or creating condenser vacuum prior to a start

Pre-activation of SCR prior to a start

Pre-heating GT fuel prior to a start

Figure 14 shows a proposed method for using stored thermal energy to reduce start- up times (ie time to full load) for a conventional CCGT power plant. Steam from the Thermal Energy Storage System is used to perform the five functions listed above to reduce start-up times. A further option is also shown in Figure 14, whereby steam generated by the Thermal Energy Storage System 1401 can be used to supplement steam from the HRSG reheat line 1424, thereby increasing the steam flow to the IP turbine and increasing total output from the plant.

Normally, the HRSG can only commence warming when the GT has been ignited, since it is the thermal energy in the GT exhaust that provides the heat for warming. The GT cannot ramp to generate more power and exhaust heat until the SCR has been activated to manage the NOX emissions, condenser vacuum is established to enable steam bypass from ST to condenser, ST gland seals established to exclude oxygen ingress and stabilise water chemistry of the system and fuel gas warmed to operating temperature. Stored thermal energy can be used to generate steam to maintain condenser vacuum, keep ST gland seals intact, keep the SCR activated and preheat fuel gas to allow the GT to ramp earlier to warm the HRSG. Stored thermal energy can be used to keep the HRSG hot in between shutdown and next start up or to pre-heat the HRSG in advance of the GT being ignited to allow the GT to ramp faster. The Thermal Energy Storage System can be used to generate steam that can then be directed to the harps, headers and steam drum/drums of the HRSG to keep it hot or commence pre-heating in advance of the GT being ignited. This will reduce the time required to bring the HRSG up to full load from the time the GT start sequence is initiated by allowing the GT to ramp earlier and faster.

In the case of a hot start, 7 minutes is required to create condenser vacuum and 18 minutes for the SCR to be activated and ST gland seals established. It takes a further 18 minutes to warm the HRSG, ST and steam piping with the GT held at partial load. This period commences from the point of ignition of the GT. Once warmed, the lead GT and ST reaches half load 53 minutes from start. The lag GT is then able to start with another hold time to warm the lag HRSG and the system finally at full load 77 minutes from start.

By using the Thermal Energy Storage System to keep the system hot, it may be possible to have the system at full load (both GT's, both HRSG's and ST at full load) in 27 minutes thereby reducing start-up time by 50 minutes in the case of a hot start.

In the case of a warm start, the time reduction due to the Thermal Energy Storage

System keeping the system hot, could be as much as 111 minutes, and for a cold start the start-up time could be reduced even more, however, the amount of thermal storage required would increase also. It is to be noted that these time reductions could be significantly more as the size and/or age of the plant increases.

ACCELERATED START-UP SEQUENCE AND TIMING USING A THERMAL

ENERGY STORAGE SYSTEM AS AN EXTERNAL STEAM SOURCE

If the Thermal Energy Storage System was used to supply external steam to keep the steam system at operating temperature 8-12 hours after shut down (i.e. a hot start), the time from the initiation of the GT start sequence to full load is approximately 27 minutes, a reduction of approximately 50 minutes over a conventional start-up.

If the Thermal Energy Storage System was used to supply external steam to reduce the start-up time as much as possible for a warm start, from the initiation of the GT start sequence it takes approximately 34 minutes before the CCGT power plant is at full load, a reduction of approximately 111 minutes over a conventional start-up. Pre-heating steam from the thermal energy storage system would need to be generated approximately 30 to

60 minutes prior to GT start-up initiation.

If the Thermal Energy Storage System was used to supply external steam to reduce the start-up time as much as possible for a cold start, from the initiation of the GT start sequence it takes approximately 60 minutes before the CCGT power plant is at full load, a reduction of approximately 170 minutes over a conventional start-up. Pre-heating steam from the thermal energy storage system would need to be generated approximately 60 to 120 minutes prior to GT start-up initiation.

RESULTS

Table 5 below summarize key data a hot start, a warm start and a cold start for a CCGT with thermal energy storage modules.

Table 5: Summary of key data for start-up of a CCGT with thermal energy storage modules based on a typical CCGT with 2 x 7FA GT's, 2 x HRSG's and 1 x Dl 1 ST

I TYPICAL DURATIONS OF STEPS DURING START-UP - CONVENTIONAL CCGT | I WITH THERMAL ENERGY STORAGE PROVIDING STEAM KEEPING SYSTEM HOT j

Notes:

1. Some of the steps during the start-up process overlap, so the total time to full load for the plant is somewhat less than the sum of the durations listed in the table above. This is discussed in greater detail elsewhere in this document. OFF-PEAK FEEDWATER PRODUCTION

The high temperature once through system used to produce steam in the thermal energy storage modules 1402, 1403 & 1404 requires a high level of water treatment which otherwise would be a parasitic load on the system. Therefore a further mechanism for conserving energy usage is to use surplus or off peak power to operate water treatment equipment 1345 in Figure 13. The feedwater system may use salt water sourced, for example, from the sea, plant make-up water, collected rain water, or brackish water sourced, for example, from a river (or otherwise 'dirty' water) as its raw supply. In Figure 13 the raw water storage tank 1344 will hold this untreated water ready for treatment by the purification apparatus 1345 and storage as treated water in the treated water storage tank 1346. If the treated water storage tank is sufficiently large to hold water for a significant period of operation of the plant, such as a day, then the water may be treated during periods of excess energy production and stored in the treated water storage tank for use when required such as during CCGT plant start-up. The water treatment apparatus 1345 may use a variety of processes such as Reverse Osmosis, Multi-Stage Flash (MSF) distillation or Multi-Effect Distillation (MED) to desalinate water for the plant's feed water and/or electro-de-ionisation (EDI) to polish the plant recycled water.

Stored thermal energy can also be used to keep the gas turbine hot prior to combusted fuel being supplied to the gas turbine by circulating air or gas (such as an inert gas) through the heat storage modules to heat the air or gas and then supply the heated air or gas into the gas turbine.

It will be appreciated by persons skilled in the art that numerous variations and/or modifications may be made to the above-described embodiments, without departing from the broad general scope of the present disclosure. The present embodiments are, therefore, to be considered in all respects as illustrative and not restrictive.

Claims

1. A method of operating a combined cycle gas turbine power generating system, comprising a gas turbine, a heat recovery steam generator and a steam turbine system, the method comprising:

a) storing energy in the form of heat energy; and

2. The method of claim 1 wherein the stored heat energy is used to heat a steam drum or steam drums of the heat recovery steam generator.

3. The method of claim 2 wherein the heat energy, or at least some of the heat energy, is stored in feed water of the heat recovery steam generator.

4. The method of claim 2 wherein the heat energy, or at least some of the heat energy, is stored in a feed water storage tank.

5. The method of claim 1, 2, 3 or 4 wherein the stored heat energy is used to heat a turbine of the steam turbine system.

6. The method of claim 1, 2, 3, 4 or 5 wherein the stored heat energy is used warm the gas turbine prior to combusted fuel being supplied to the gas turbine.

7. The method as claimed in any one of the preceding of claims wherein the stored heat energy is used to heat steam pipes which deliver steam from the heat recovery steam generator to the steam turbine system.

8. The method of claim 7 wherein the stored heat energy is used to heat steam pipes which deliver steam from the heat recovery steam generator to a high pressure turbine of the steam turbine system, the heating being via steam tracing along the pipes to the high pressure turbine.

9. The method of claim 7 wherein the stored heat energy is used to heat steam pipes which deliver steam from the heat recovery steam generator to the high pressure turbine and/or an intermediate pressure turbine and/or an low pressure turbine of the steam turbine system, the heating being achieved by passing steam through the pipes to the high pressure turbine and/or the intermediate pressure turbine and/or low pressure turbine.

10. The method of claim 9 wherein the stored heat energy is used to heat the high pressure turbine and/or the intermediate pressure turbine and/or the low pressure turbine of the steam turbine system, the heating being achieved by passing steam through the high pressure turbine and/or the intermediate pressure turbine and/or the low pressure turbine.

11. The method of claim 11 wherein the steam passed through the high pressure turbine and/or the intermediate pressure turbine and/or low pressure turbine is used to operate the high pressure turbine and/or the intermediate pressure turbine and/or the low pressure turbine to generate electricity while the gas turbine and heat recovery steam generator are being brought on-line.

12. The method as claimed in any one of the preceding claims wherein the heat energy is stored in one or more bodies of heat storage material which are electrically heated by resistive heating elements.

13. The method of claim 12 wherein the heat storage material is heated using electrical energy generated in excess to a current demand provided by a consumer load.

14. The method of claim 13 wherein the electrical energy generated in excess to the current demand is renewable energy.

15. The method of claim 13 wherein the renewable energy is generated by solar power generation.

16. The method of claim 13 wherein the electrical energy generated in excess to current demand is generated by non-renewable sources during dips in demand or during periods where they are being shut down and are generating more energy than is required by the consumer load.

17. The method as claimed in any one of claims 12 to 16 wherein the body or bodies of heat storage material comprise graphite enclosed in a gas tight housing.

18. The method of claim 17 wherein the graphite in the gas tight housing is heated by radiative heaters positioned adjacent to each gas tight housing.

19. The method of claim 17 or 18 wherein heat is extracted from the graphite via a heat transfer fluid passed through tubes embedded in the graphite and extending through the gas tight housing.

20. The method of claim 19 wherein the heat transfer fluid is water/steam and is delivered directly to the components to be heated via steam pipes.

21. The method as claimed in claim 20 wherein water delivered to the graphite to create steam is produced by treating raw water and storing the treated water in a treated water storage tank for use at a later time.

22. The method of claim 21 wherein the treatment of the raw water and storage in the treated water storage tank is performed during period of excess energy production whereby energy produced in excess of user demand is used to power the treatment process.

23. The method of claim 21 or 22 wherein the treatment process comprises Reverse Osmosis, Multi-Stage Flash (MSF) distillation, Multi-Effect Distillation (MED), or Electro deionisation (EDI).

24. The method of claim 21 or 22 wherein the raw water is salt water, brackish water, plant make-up water, or collected rain water.

25. A combined cycle gas turbine power generating system, comprising:

a gas turbine,

a heat recovery steam generator;

a steam turbine system;

26. The combined cycle gas turbine power generating system of claim 25 wherein the distribution system connects the energy storage system to a steam drum of the heat recovery steam generator.

27. The combined cycle gas turbine power generating system of claim 26 wherein the heat storage system comprises feed water of the heat recovery steam generator.

28. The combined cycle gas turbine power generating system of claim 27 wherein the heat storage system comprises a feed water storage tank.

29. The combined cycle gas turbine power generating system of claim 25, 26, 27 or 28 wherein the distribution system connects the energy storage system to a turbine of the steam turbine system.

30. The combined cycle gas turbine power generating system of claim 25, 26, 27, 28 or 25 wherein the stored heat energy is used warm the gas turbine prior to combusted fuel being supplied to the gas turbine.

31. The combined cycle gas turbine power generating system as claimed in any one of the preceding of claims wherein the distribution system connects the energy storage system to steam pipes which deliver steam from the heat recovery steam generator to the steam turbine system.

32. The combined cycle gas turbine power generating system of claim 31 wherein the distribution system connects the energy storage system to steam pipes which deliver steam from the heat recovery steam generator to a high pressure turbine of the steam turbine system, the heating being via steam tracing along the pipes to the high pressure turbine.

33. The combined cycle gas turbine power generating system of claim 31 wherein the distribution system connects the energy storage system to steam pipes which deliver steam from the heat recovery steam generator to an intermediate pressure turbine and/or an low pressure turbine of the steam turbine system, the distribution system delivering steam through the pipes to the intermediate pressure turbine and/or low pressure turbine.

34. The combined cycle gas turbine power generating system of claim 33 wherein the distribution system connects the energy storage system to the intermediate pressure turbine and/or the low pressure turbine of the steam turbine system, the distribution system delivering steam through the intermediate pressure turbine and/or low pressure turbine.

35. The method of claim 34 wherein the steam passed through the intermediate pressure turbine and/or low pressure turbine is used to operate the intermediate pressure turbine and/or low pressure turbine to generate electricity while the gas turbine and heat recovery steam generator are being brought on-line.

36. The combined cycle gas turbine power generating system of claim 35 wherein electrical heaters are located to heat the heat storage material, the heaters comprising resistive heating elements connected to an electrical supply to use electrical energy generated in excess to a current demand provided by a consumer load.

37. The combined cycle gas turbine power generating system of claim 36 wherein the electrical supply includes a renewable energy source.

38. The combined cycle gas turbine power generating system of claim 36 wherein the renewable energy source is a solar energy source.

39. The combined cycle gas turbine power generating system of claim 36 wherein the electrical supply includes a non-renewable source to supply energy during dips in demand or during periods where the non-renewable energy source is being shut down and are generating more energy than is required by the consumer load.

40. The combined cycle gas turbine power generating system as claimed in any one of claims 35 to 39 wherein the body or bodies of heat storage material comprise graphite enclosed in a gas tight housing.

41. The combined cycle gas turbine power generating system of claim 40 wherein radiative heaters are positioned adjacent to each gas tight housing to heat the graphite.

42. The combined cycle gas turbine power generating system of claim 40 or 41 wherein tubes embedded in the graphite and extending through the gas tight housing arranged to carry a heat exchange fluid to extract heat from the graphite.

43. The combined cycle gas turbine power generating system of claim 42 wherein the heat transfer fluid is water/steam and the heat distribution system comprises steam pipes connected to the tubes embedded in the graphite to deliver hot water and/or steam directly to the components to be heated.

44. The combined cycle gas turbine power generating system of claim 43 wherein water delivered to the tubes embedded in the graphite to create the steam is produced in a water treatment apparatus that treats raw water and stores the treated water in a treated water storage tank for use at a later time.

45. The combined cycle gas turbine power generating system of claim 44 wherein the water treatment apparatus is powered by energy produced during periods of excess energy production when energy is produced in excess of user demand.

46. The method of claim 44 or 45 wherein the water treatment apparatus comprises Reverse Osmosis apparatus, Multi-Stage Flash distillation apparatus (MSF), Multi-Effect Distillation apparatus (MED), or Electro deionisation (EDI).

47. The method of claim 44, 45 or 46 wherein an input to the water treatment apparatus is connected to a supply of salt water, brackish water, plant make-up water, or collected rain water.