WO2015004424A2

WO2015004424A2 - Steam power cycle

Info

Publication number: WO2015004424A2
Application number: PCT/GB2014/051999
Authority: WO
Inventors: Frederick Egglestone
Original assignee: Aopc Limited
Priority date: 2013-07-08
Filing date: 2014-07-02
Publication date: 2015-01-15
Also published as: GB201520402D0; WO2015004424A3; GB2529587B; GB201312232D0; GB2529587A

Abstract

An environmentally benign steam power cycle (10) facilitates separation and capture of carbon dioxide from its combustion products. In the steam power cycle an oxy-combustion superheater (12) superheats steam (13A) previously evaporated from feedwater (28) in a steam generator (20), the resulting superheated steam and combustion products being used to drive a steam turbine (16) for power generation (18). The feedwater (28) is evaporated, referably raised to at least its critical point, and preferably given some superheat, by regenerative heat exchange in the steam generator, which comprises a heat exchange network (20A, 20B), in which (i) sensible heat is transferred to the feedwater from the exhaust stream of the turbine and (ii) sensible and latent heat is transferred to the feedwater from a plurality of turbine bleed streams (P1, P2, P3), including a turbine bleed stream (P1) taken at about half the critical pressure of steam from just after the highest pressure stage (14,15) of the turbine, and (iii) sensible heat is transferred to the feedwater from condensates of the turbine bleed streams. The feedwater (28) for the steam generator is produced by (i) condensation of steam from the turbine bleed streams (P1, P2, P3) during transfer of their heat of condensation to the feedwater in a plurality of heat exchange stages, and (ii) condensation of steam from the turbine exhaust stream (E) after transfer of its sensible heat to the feedwater in a plurality of heat exchange stages. Carbon dioxide produced in the oxy-combustion process is easily captured (26, 36) when the steam from the turbine exhaust stream and the turbine bleed streams is condensed, thereby leaving most of the carbon dioxide behind as a gas to be extracted from the cycle.

Description

STEAM POWER CYCLE

Technical Field

The present disclosure relates to thermodynamic power cycles and in particular to power cycles employing oxy-combustion to drive steam turbines.

Technical Background

Many combined cycle power plants for electricity generation are currently being built due to their greater thermal efficiency compared with single cycle plants. A typical combination is a gas turbine burning natural gas or gasified coal, whose exhaust is passed through a heat exchanger to raise steam for a steam turbine. In order to reduce the amount of carbon dioxide (C0₂) entering the atmosphere due to burning of fossil fuels, there is a need to capture and sequester the C0₂ produced by combined cycle power plants, but this is costly in Operational and Capital Expenditure (OPEX and CAPEX). An alternative technology showing promise in this regard is oxy-combustion, in which nominally pure oxygen replaces the atmospheric air normally burnt with fossil fuels, the fuel and oxygen being burnt within the steam part of a steam/water loop so that the C0₂ produced by the combustion process is mixed with the steam working fluid of the cycle, but without any substantial amount of nitrogen or its combustion products. When the steam is condensed for recycling as boiler or steam generator feed water, most of the C0₂ that was mixed with the steam is left behind in the condensers, from where it can be extracted for compression and transmission to a CO₂ storage site. Any carbon dioxide dissolved in the steam condensate, along with other impurities that could cause problems in the cycle, can be removed in a water treatment plant. An oxy-combustion combined cycle therefore intrinsically includes separation of C02 from the combustion products, unlike conventional combined cycle power plants. In the latter, separating the C02 from the rest of the boiler flue gas is an "add-on" process, which increases plant operating costs and hence increases the cost of electricity generated by the plant. A drawback associated with known oxy-combustion cycles is the need to incorporate an air separation plant into the power producing plant in order to supply the oxygen for combustion. This significantly increases the plant capital and operating costs, and reduces its efficiency. There is therefore a need to improve the commercial viability of oxy-combustion steam cycles by improving their efficiency to at least offset the cost of the oxygen supply.

In some known oxy-combustion steam cycle designs, the steam is superheated to a temperature of circa 1450 deg. C before the steam enters the turbine inlet plenum chamber. Consequently, the inlet plenum of the turbine is subject to this temperature, requiring extensive internal insulation of the plenum's pressure containment parts, which experience high pressures, thereby adding to expense and complexity of the system. Cooling of the plenum's pressure containment system may also be required to ensure its integrity in the event of a breakdown of the insulation, which again would add expense and complexity.

Definitions and Discussion of Thermodynamic Terms of Art

As used herein, "critical pressure" means the vapour pressure at the critical point on a pressure/temperature phase diagram for water, above which point distinct liquid and vapour phases do not exist. For water, the critical point occurs at about 374 deg. C and 218 atmospheres, at which point and beyond the water becomes a homogenous supercritical fluid. The heat of vapourisation (i.e., enthalpy of evaporation) becomes zero at and above the critical point. "Supercritical" must be distinguished from "superheated". Superheated steam is steam which has been heated above the critical point or vapourisation point (boiling point) of the water, the degree of superheat being the number of degrees it has been heated above its saturation temperature or critical temperature. The saturation temperature of water is its boiling point, which varies with pressure; therefore more heat energy (i.e., enthalpy of water, or sensible heat) is needed to raise the water's temperature to saturation point at higher pressures than at lower pressures. On the other hand, less heat energy (i.e., enthalpy of evaporation or latent heat) is needed to vapourise the water into steam at higher pressures than at lower pressures, because the specific enthalpy of evaporation (enthalpy per unit mass of water evaporated) decreases as the steam pressure increases. Thus, we find that the combined latent and sensible heat of water increases as the steam pressure increases, up to a point where the total enthalpy begins to decrease and then becomes a minimum when its critical point is reached. Where the present disclosure refers to turbine bleed steam, it means steam bled from a turbine just after a stage of the turbine, or just after each of a plurality of stages of the turbine. Summary

The new thermodynamic cycle proposed here is an advanced type of oxy-combustion steam power cycle that is expected to be more efficient and less costly to operate than combined cycle plants, despite needing oxygen for combustion. The cycle employs oxy-combustion to superheat steam by direct contact with the products of combustion from nominally pure oxygen and a gas fuel such as hydrocarbon, carbon monoxide or hydrogen. The cycle uses this steam, preferably at or above its critical pressure, as the working fluid, and while having some similarity to the Rankine cycle it has major differences.

Broadly, the concept presented herein is a steam power cycle in which, during normal operation of the cycle at full load, a superheating oxy-combustion process is supplied with fuel, oxygen and steam, the steam comprising feedwater previously evaporated in a steam generator, the superheating oxy-combustion process thereby producing high temperature superheated steam and combustion products that are used to drive a steam turbine arrangement to produce shaft power, the feedwater having been evaporated in the steam generator by regenerative heat exchange comprising (i) transfer of sensible heat to the feedwater from an exhaust stream of the turbine and (ii) transfer of sensible heat and latent heat of condensation to the feedwater from at least one turbine bleed stream, the feedwater for the steam generator being produced by (i) condensation of turbine bleed steam during transfer of its latent heat of condensation to the feedwater and (ii) condensation of steam from the turbine exhaust stream after transfer to the feedwater of sensible heat above the point of condensation of steam in the exhaust stream.

Alternatively expressed, a method of operating a steam power cycle comprises the steps of:

(a) supplying a superheating oxy-combustion process with fuel, oxygen and steam, the steam being supplied as a diluent to the combustion process;

(b) driving a steam turbine arrangement with superheated steam and combustion products produced by the oxy-combustion process, thereby to produce power from the cycle; (c) evaporating feedwater in a steam generator by regenerative heat exchange with a turbine exhaust stream and at least one turbine bleed stream, wherein the turbine exhaust stream gives up sensible heat to the feedwater and each turbine bleed stream gives up sensible heat and latent heat of condensation to the feedwater;

(d) producing the feedwater for the steam generator by condensing steam from the turbine exhaust stream and combining the resulting condensate with condensate from the at least one turbine bleed stream; and

(e) recycling the feedwater through step (c) and passing it to step (a). Preferably, the method also includes reheating the products of the superheating combustion process after said products have passed through a high pressure turbine and discharging said reheated combustion products into a lower pressure turbine, said reheating comprising a second oxy-combustion process supplied with fuel and oxygen. During operation of the cycle it is advantageous to raise the evaporated feedwater to at least its critical point by said regenerative heat exchange.

Because carbon dioxide is not significantly soluble in hot water, carbon dioxide can be extracted from the cycle for storage and sequestration when steam from the turbine exhaust stream and each turbine bleed stream is condensed (assuming such condensation occurs at about 100 deg. C and lower).

The steam from the steam generator should preferably be supplied to the superheating oxy- combustion process at a pressure sufficiently above the steam's critical pressure, and with sufficient superheat, to obviate condensation of steam due to reduction of the steam's partial pressure upon entry to the superheating oxy-combustion process.

Preferred gaseous fuel for the superheating and reheating combustion processes may be selected from the following: a hydrocarbon gas, hydrogen, or carbon monoxide, and the fuel may be diluted with carbon dioxide to temper the oxy-combustion process if it is too vigorous.

Unlike the presently proposed cycle, most oxy-steam power cycles use relatively low-pressure turbine bleed steam. Moreover, conventional steam power cycles use turbine bleed steam mainly for raising the feed-water temperature above the acid dew-point of the boiler flue gas, otherwise the heat exchanger tubes would have a short life due to corrosion, whereas in the presently proposed cycle the turbine exhaust gas is in principle not corrosive, provided that the fuel is a hydrocarbon gas or hydrogen and, in the case of a hydrocarbon gas, combustion is completed before the fuel is cracked by the heat.

Also disclosed herein is a method of combustion applicable to the present steam power cycle - but also applicable more generally to oxy-combustion processes involving steam as a diluent - in which minor proportions of steam and fuel are supplied to an ignition zone of the combustion process, together with enough oxygen to burn all the fuel admitted to the combustion process. In this combustion method, major proportions of the steam and fuel are distributing peripherally and longitudinally of the oxy-combustion process downstream of the ignition zone, the steam entering the combustion process as a diluent and the fuel being carried into the combustion process by the diluent steam. Preferably, the fuel gas is released into the diluent steam just as the steam enters the combustion process.

In the present cycle it is advantageous to admit the steam to the superheating combustion process via a steam inlet box of the turbine and discharge the combustion products directly into inlet nozzles of the turbine, which may be attached to the exit face of the steam inlet box.

While it is preferable if possible to run the turbine inlet nozzles close to being choked, in order to obtain even distribution of the steam into the oxy-combustion process and even distribution of the superheated efflux into the turbine inlet nozzles, the turbine designer may need to reduce the percentage of choke to ensure that the pressure of the high pressure turbine bleed steam is as required for transfer of its latent heat of condensation to the feedwater. This is particularly the case if the regenerative heat exchange process in the steam generator is generating steam at below critical pressure during low load conditions.

The method of operating the present cycle involves taking at least one turbine bleed stream from a high pressure turbine stage, but preferably taking a plurality of turbine bleed streams in descending order of pressure from a corresponding plurality of turbine stages comprising a high pressure stage and at least one lower pressure stage. The steam in the turbine bleed stream taken from a high pressure turbine stage is preferably at a partial pressure of about half the critical pressure of steam.

Although it is believed possible to take between two and five separate bleed streams from turbine stages at different pressures, it is presently preferred to take a high pressure bleed stream, a medium pressure bleed stream and a lower pressure bleed stream from corresponding turbine stages.

Although not a preferred expedient, it would be possible to replace the high pressure turbine bleed stream by taking a small proportion of the critical pressure steam produced by the steam generator and superheating it sufficiently such that when its pressure is reduced upon entry to the combustion process, no steam condensate is formed. The heat for superheating the above small proportion of critical pressure steam can come from at least one turbine bleed stream that is hotter than the turbine exhaust temperature. If such turbine bleed stream heat is insufficient for the task, the cycle heat balance could be restored by a small increase in the turbine exhaust temperature.

Heat to replace the high pressure turbine bleed stream may alternatively come from an air separation unit (ASU) used to supply the oxygen for combustion in the superheater. It would be possible to use heat rejected from the ASU by inputting it to the feedwater through the steam generator. This would also increase the efficiency of the cycle.

It is contemplated that after the turbine exhaust stream has passed through the steam generator, steam in the turbine exhaust stream will be condensed by using atmospheric air as a heat sink, this condensation probably occurring at about atmospheric pressure or just above atmospheric pressure.

In order to produce steam at the preferred temperature and pressure for supply to the superheater, it is necessary to raise the feedwater temperature from at or below its condensation temperature to at least its critical temperature by means of regenerative heat exchange in the steam generator. To achieve this, the steam generator should comprise a heat exchange network including a plurality of heat exchange stages arranged sequentially to input heat to the feedwater in ascending order of feedwater temperature. In accordance with the present concept, the heat exchange stages are arranged to perform the following heat transfers to the feedwater:

(a) sensible heat from the turbine bleed stream(s) when cooling from a superheat temperature upon exit from the turbine, down to saturation temperature;

(b) latent heat of condensation of the bleed steam;

(c) sensible heat from the bleed steam condensate; and

(d) sensible heat from the turbine exhaust before it has cooled down to its condensation temperature. To achieve a desirable amount of superheat in the steam supply to the superheater, the above preferably involves:

(a) converting feedwater to steam at critical pressure and temperature by using a combination of (i) latent heat from condensation of the turbine bleed steam, (ii) sensible heat from the turbine exhaust stream, (iii) sensible heat from turbine bleed stream(s) below the turbine exhaust exit temperature, (iv) sensible heat from turbine bleed steam condensate; and

(b) raising feedwater steam temperature from the critical temperature to a superheat temperature using sensible heat from turbine bleed stream(s) above the turbine exhaust exit temperature. Assuming the availability of a high pressure bleed stream, a medium pressure bleed stream and a lower pressure bleed stream as previously mentioned, the heat exchange stages mentioned above may particularly include the following heat transfers:

(a) in a first stage of heat exchange, transferring latent heat from condensation of all three bleed streams to the feedwater, together with sensible heat from the condensates of the high and medium pressure bleed streams;

(b) in a second stage of heat exchange, transferring latent heat from condensation of the high and medium pressure bleed streams to the feedwater, together with sensible heat from the low pressure bleed stream above its condensation temperature, but below the turbine exhaust exit temperature, and sensible heat from condensate of the high pressure bleed stream;

(c) in a third stage of heat exchange, transferring latent heat from condensation of the high pressure bleed stream to the feedwater, together with sensible heat from the low and medium pressure bleed streams above their condensation temperatures, but below the turbine exhaust exit temperature; (d) in a fourth stage of heat exchange, transferring to the feedwater sensible heat from the high, medium and low pressure bleed streams above their condensation temperatures, but below the turbine exhaust exit temperature;

(e) in a fifth stage of heat exchange, transferring to the feedwater sensible heat from the high, medium and low bleed pressure streams above the turbine exhaust exit temperature;

wherein, in each of the above heat exchange stages, sensible heat from the turbine exhaust stream is also transferred to the feedwater.

For economic and mechanical reasons concerned with construction of heat exchangers comprising the above heat exchange stages, the last stage of heat exchange - in which sensible heat from the high, medium and low bleed pressure streams above the turbine exhaust exit temperature is transferred to the feedwater - may combine the steps of first adding the bleed stream heat above the turbine exhaust exit temperature to the turbine exhaust stream and then transferring the added heat in the turbine exhaust stream to the feedwater.

According to the steam generator design presented hereafter, at each stage of heat exchange, the heat transfers to the feedwater should occur in parallel with all other heat transfers to the feedwater in the same stage. Also disclosed herein is a steam power system comprising:

(a) a superheater comprising an oxy-fired combustor arrangement for burning gaseous fuel with oxygen in an oxy-combustion process, with steam as a diluent to the combustion process;

(b) a steam turbine arrangement driven by superheated steam and combustion products from the superheater thereby to produce power from the cycle;

(c) a steam generator for evaporating feedwater by regenerative heat exchange with a turbine exhaust stream and at least one turbine bleed stream, wherein the turbine exhaust stream gives up sensible heat to the feedwater and each turbine bleed stream gives up sensible heat and latent heat of condensation to the feedwater, whereby preferably the evaporated feedwater is raised to at least its critical point and is preferably given sufficient superheat to obviate condensation of steam due to reduction of the steam's partial pressure upon entry to the oxy-combustion process; and (d) condensing heat exchangers for condensing steam from the turbine exhaust stream and the at least one turbine bleed stream, the resulting condensates being combined to produce feedwater for recycling through the steam generator, thereby to produce the diluent steam for the oxy-combustion process.

To increase the efficiency and power output of the system, the system is preferably provided with a reheater comprising a second oxy-combustion arrangement provided with inputs for oxygen and fuel. The reheater can be located between a high pressure turbine and a lower pressure turbine of the steam turbine arrangement in order to reheat the efflux of the high pressure turbine and discharge it through the lower pressure turbine.

The condensing heat exchangers are constructed to allow extraction of carbon dioxide from the cycle when steam in the turbine exhaust stream and each turbine bleed stream is condensed therein.

It is advantageous if the superheater comprises a steam inlet box adjoining, or preferably containing, the oxy-fired combustor arrangement, whose combustion chambers discharge directly into inlet nozzles of the steam turbine arrangement, so that at least to this extent, the steam turbine is configured as an internal combustion turbine. The turbine entry nozzles may conveniently be attached to an exit face of the steam inlet box, which should directly receive steam from the steam generator. Due to the high pressures and temperatures at which the combustion process operates, the steam inlet box containing the superheater's oxy-fired combustor arrangement can be of such dimensions as to be contained within a pressure casing of the steam turbine arrangement.

The oxy-fired combustor arrangements in the superheater or the reheater may be applicable to other types of oxy-combustion systems and may comprise: (i) a circular array of discrete combustion chambers, or (ii) two cannular combustion chambers comprising upper and lower half-annular combustion chambers, or (iii) a fully annular combustion chamber. Alternatively, the oxy-fired combustor arrangements may comprise either (i) upper and lower semi-toroidal combustion chambers; or (ii) upper and lower semi-annular combustion chambers; the upper and lower combustion chambers being arranged to receive oxygen, fuel and air through ducts centred on a vertical axis. The outlets of the combustion chambers are preferably close-coupled to turbine entry nozzles.

It is envisaged that the combustion chambers will be provided with burners for supplying ignition zones of the chambers with all the oxygen necessary for combustion, a minor proportion of the diluent steam and a minor proportion of the fuel; the combustion chambers being adapted to distribute the rest of the fuel and steam longitudinally and peripherally of the combustion process to combine with oxygen not burnt during ignition. In this design, portions of the combustion chambers surrounding the combustion process are preferably provided with plunge holes for admitting jets of steam to dilute the combustion process, fuel being delivered to the combustion process mixed with the steam. Fuel can be distributed to the combustion process downstream of the ignition zone through ducts around combustion chamber outer surfaces, the ducts having small exit holes through which fuel can flow onto said outer surfaces by the Coanda effect and immediately mix with diluent steam flowing through the plunge holes.

Although the number of turbine bleed streams taken from the steam turbine arrangement may be varied within certain limits, it is believed that an optimum number of turbine bleed streams may be three, comprising a high pressure bleed stream, a medium pressure bleed stream and a lower pressure bleed stream taken from corresponding turbine stages., the high pressure bleed stream being taken at a partial pressure of about half the critical pressure of steam.

However, as previously mentioned, it would be possible to replace the heat that the high pressure bleed stream inputs to the feed water, either by heat rejected from an air separation unit supplying oxygen to the oxy-combustors in the cycle, or by heat taken from elsewhere within the cycle, i.e., by heat from steam that has been extracted from the steam generator and superheated by one or more other turbine bleed streams while their temperatures are above the turbine exit temperature. A significant part of the present concept is the steam generator, which comprises a heat exchange network including a plurality of heat exchange stages arranged sequentially to input heat to the feedwater in ascending order of feedwater temperature, thereby to raise the feedwater temperature from at or below its condensation temperature to at least its critical temperature by means of regenerative heat exchange. The heat exchange stages are arranged to transfer to the feedwater:

(a) sensible heat of the turbine bleed stream(s) when cooling from a superheat temperature upon exit from the turbine, down to saturation temperature;

(b) latent heat of condensation of the bleed steam;

(c) sensible heat of the bleed steam condensate; and

(d) sensible heat of the turbine exhaust before it has cooled down to its condensation temperature. For efficiency of heat exchange, and in respect of heat exchange stages that comprise multiple heat exchangers, it is arranged that the feedwater passes through each such heat exchange stage in a plurality of flow paths, wherein a flow path in each such heat exchange stage is dedicated to sensible heat transfer from the turbine exhaust stream to the feedwater, and wherein such heat transfer from the turbine exhaust stream to the feedwater occurs in parallel with transfer to the feedwater of:

(a) sensible heat of one or more turbine bleed streams when cooling from a superheat temperature upon exit from the turbine, down to saturation temperature;

(b) latent heat of condensation of the bleed steam; and

(c) sensible heat of the bleed steam condensate;

To increase efficiency of the cycle, the heat exchange stages are arranged to:

(a) convert the feedwater to steam at critical pressure and temperature by using a combination of (i) latent heat from condensation of the turbine bleed steam, (ii) sensible heat from the turbine exhaust stream, (iii) sensible heat from turbine bleed stream(s) below the turbine exhaust exit temperature, (iv) sensible heat from turbine bleed steam condensate; and

(b) raise feedwater steam temperature from the critical temperature to a superheat temperature using sensible heat from turbine bleed stream(s) above the turbine exhaust exit temperature. In order to achieve the above transfer of sensible heat above the turbine exhaust exit temperature to the feedwater in way which reduces CAPEX and eases mechanical aspects of heat exchanger design, the last stage of heat exchange first adds the bleed stream heat above the turbine exhaust exit temperature to the turbine exhaust stream and then transfers the added heat in the turbine exhaust stream to the feedwater.

Each heat input to the feedwater in each heat exchange stage should be made in parallel with all other heat inputs to the feedwater in the same heat exchange stage.

Brief Description of the Drawings

Embodiments will now be described with reference to the accompanying drawings, which are not to scale, and in which:

Figure 1 schematically shows the main components of a system for implementing an oxy-combustion steam cycle as disclosed herein;

Figure 2A schematically illustrates a first possible embodiment of an oxy-combustion superheater for use in the system of Figure 1, comprising a sectional end elevation of a quadrant of a turbine inlet plenum, looking on the ends of combustor cans which feed their effluxes directly into turbine inlet nozzles;

Figure 2B represents a sectional side elevation of the combustor and turbine inlet nozzle in Figure 2A;

Figure 2C schematically illustrates a second possible embodiment of an oxy- combustion superheater for use in the system of Figure 1, comprising a part-sectional end elevation of the upper half of a semi-toroidal combustor, which feeds its efflux directly into turbine inlet nozzles;

Figure 3 is a graph plotting temperature against enthalpy to compare heat demand with the supply of sensible heat in the system of Figure 1;

Figure 4 is graph plotting temperature against enthalpy to compare heat demand with the supply of sensible heat and latent heat in the system of Figure 1; and

Figure 5 is a schematic diagram illustrating a heat exchange network forming part of the system shown in Figure 1, which functions as an unfired "once-through" critical pressure steam generator and superheater to raise steam for the oxy-combustion steam cycle.

Detailed Description of Various Embodiments

To ease those parts of the following description that relate to heat exchange, it will be assumed that where heat transfer occurs, and a minimal temperature difference is favourable, there will be no significant temperature difference between fluid streams that are exchanging heat, so that they may be considered to have the same terminal temperatures at points of convergence. In practice, for a fully engineered system, such terminal temperatures may differ by about 10 deg. C.

Overview of Figure 1

Referring now to the accompanying drawing figures, Figure 1 shows diagrammatically the main parts of an oxy-combustion steam cycle system 10, in which the hidden internals of the system are indicated by dashed lines. The system 10 is suitable for use in a power station supplying electric power to a utility grid. In the system 10, recirculated feedwater 28 is evaporated to steam by a regenerative heat exchange network (HEN) 20. HEN 20 functions as an unfired "once-through" critical pressure steam generator, intended during normal operation of the system to heat the steam up to at least its critical point, and preferably give it a few degrees of superheat. This improves efficiency by recycling high grade heat to the combustor and also ensures no water is carried through to the combustor. For electricity generation, normal operating conditions for the system of Figure 1 would be full load operation.

The total steam flow generated by HEN 20 issues as two separate streams, 13A and 13B. Stream 13 A, comprising the major part of the total steam flow, issues from HEN 20 as superheated steam at or above its critical point and is used to supply superheater 12. Stream 13B also issues at or above its critical pressure, but at a lower temperature, and is used to cool components at the high temperature and pressure end of a multi-stage, axial flow, critical pressure turbine 16, such components being, e.g., inlet nozzles 14A and first stage moving blades 15 A. Superheater 12 comprises a critical pressure steam inlet box 12A containing an oxy- fired primary combustor arrangement 12B whose exits (not shown in Figure 1) discharge directly into the first stage turbine entry nozzles 14 A, which are attached to the exit face of the box 12 A. Box 12 A itself is contained within a part of the turbine casing 16C, which is thereby insulated from the effects of steam 13 A and holds a lesser pressure. Box 12 A initially receives the steam 13 A, and the oxy-fired combustor arrangement 12B superheats the steam 13 A by combustion of gaseous hydrocarbon fuel HC (e.g., natural gas or other suitable fuel, such as purified syngas) with oxygen 0₂. Alternatively, a suitable non-hydrocarbon fuel may comprise hydrogen or carbon monoxide. If necessary, the fuel may also contain carbon dioxide as a diluent to temper the combustion reaction. Any other non-combustible additives that may be present in the fuel or oxygen supply should not be condensable in the feedwater 28 after they have passed through the system.

The superheater 12 therefore discharges highly superheated steam and combustion gases (essentially C0₂ and H₂0) from the combustion process into the first stage inlet nozzles 14 A of the turbine 16, which generates the shaft power necessary to drive an electrical generator 18 on shaft 19. Alternatively, other forms of turbine, such as radial flow turbines, may also be considered for use in the system 10. After supplying the power station, the remainder of the generated electricity would be distributed at a high voltage through a utility grid.

The turbine exit discharges a turbine exhaust stream E into ducting 21 and the exhaust stream E then passes through the HEN 20 to help raise the steam 13 A and 13B by heating the recirculated feed water 28. Three turbine bleed streams PI to P3 are also taken from the turbine 16 to heat the feedwater in HEN 20.

The HEN 20 is shown as comprising:

(i) a part 20A situated in exhaust ducting 21 and dedicated to transferring to the feedwater 28;

(a) heat from the exhaust stream E, and

(b) heat from the turbine bleed streams PI to P3 that is above the turbine exit temperature; and

(ii) a part 20B situated outside ducting 21 and dedicated to transferring to the feedwater heat from the turbine bleed streams PI to P3 that is below the turbine exit temperature. These heat exchange processes in HEN 20 are explained later in more detail in connection with Figures 4 and 5.

The steam 13A for injection into the superheater 12 should preferably be above its critical point and have sufficient superheat (e.g., 5 to 10 deg. C) to avoid wet steam entering the oxy- combustor 12B when its partial pressure is reduced by admixture with the fuel, any diluent C0₂, and oxygen. Wet steam can particularly be a problem during low load and start-up conditions in the turbine 16, when the heat available from the oxy-combustor 12B is less than needed to ensure complete evaporation of the feed water in the HEN 20. For this reason a supplementary oxy-combustor 17 is included in the system. The supplementary combustor is located in a bypass loop 17A to selectively receive flow 13 from part 20B of the HEN 20, the flow through the bypass loop being controlled by valves, as shown. During full load conditions, feedwater steam flow 13 is normally routed back into part 20 A of the HEN 20 without passing through supplementary combustor 17, and is heated in 20 A by the turbine bleeds PI to P3, using their heat above the turbine exit temperature to produce superheated steam 13 A, as explained in more detail later. However, whenever required, the steam flow through the bypass loop 17 A, and input of oxygen 0₂ and hydrocarbon fuel HC to the supplementary combustor 17, may be controlled in order to complete evaporation of the feed- water to at least its critical temperature. During normal full-load operation, the supplementary combustor 17 will only be used if the HEN 20 is not adding significantly to the enthalpy of the feedwater steam. A disadvantage of operating a supplementary combustor to compensate for low-load conditions is reduction of the overall cycle efficiency; nevertheless, it is believed that cycle efficiency during operation of the supplementary combustor 17 to compensate for low- load conditions would still be higher than that of known combined cycles at full load. It is believed that a system having only a primary combustor 12B discharging into turbine 16, with a supplementary combustor 17 to assist at system start-up and at low-load conditions, would be adequate to generate electricity efficiently and to provide the HEN 20 with the heat that it needs. However, for reasons explained below, the system 10 is also provided with a reheater in the form of a second oxy-combustor 23 provided part-way along the turbine 16, so dividing the turbine into a high pressure turbine 16A and a low pressure turbine 16B. For convenience, both turbines are shown as being mounted for rotation on the same shaft line 19, but this is not necessary and they could be mounted on separate shafts for rotation at different speeds, if this is desirable for greater efficiency. Like the primary combustor 12B, the reheat combustor 23 is provided with controllable supplies of fuel HC and oxygen 0₂. However, the primary and reheat combustors are used for different purposes, in that the fuel and oxygen supplies to the primary combustor 12B are modulated to control turbine load, whereas the fuel and oxygen supplies to the reheat combustor 23 are modulated to maintain a constant turbine exhaust temperature. Besides increasing the thermodynamic efficiency of the cycle, the reheat oxy-combustor also increases the maximum turbine power output. Note that the presence of reheat combustor 23 in the system reduces the need to use auxiliary combustor 17 to compensate for low-load conditions; therefore the auxiliary combustor in Figure 1 is mostly used to assist start-up of the cycle. It should be noted that, despite the provision of reheater 23, heating of the feedwater in part 20A of HEN 20 by the turbine exhaust stream E alone is insufficient to evaporate all the feedwater to its critical temperature and give it the required degree of superheat. Therefore, as mentioned earlier, turbine gas, comprising essentially steam and carbon dioxide, is bled from the turbine 16 in turbine bleed streams PI to P3 to input additional heat to the feedwater. Note that, for economic reasons and to enhance the thermodynamic efficiency of the cycle, the bleed streams PI to P3 are routed to part 20 A of HEN 20 in turbine exhaust stream E, before being routed to part 20B of HEN 20. This is done in order to transfer to the exhaust stream E that part of the superheat in the bleed streams that is above the turbine exit temperature. This added heat in the exhaust stream E is then used to superheat steam 13 before it finally leaves part 20 A of HEN 20 as superheated steam 13 A. Hence, part 20B of HEN 20 heats feedwater 32 using heat from bleed steam that has been cooled to below the exit temperature of the turbine exhaust E. These heat exchange processes in HEN 20 are explained later in more detail in connection with Figures 4 and 5.

As explained later in more detail, the present concept involves controlling the total mass flow rate of bleed streams PI to P3 so that it is sufficient to evaporate the feedwater 28 when using: (a) the sensible heat of the turbine bleed streams when cooling from their superheat temperature upon exit from the turbine 16, down to their saturation temperatures; (b) the latent heat of condensation of the bleed steam; (c) the sensible heat of the bleed steam condensate; and (d) the sensible heat of the turbine exhaust before the HEN has cooled down the turbine exhaust stream E to its condensation temperature. As an alternative to active control of bleed stream flow rates, it seems possible that the bleed stream flows may be self-controlling as the feed-water temperature converges close to the condensing temperature of each bleed stream; hence, heat transfer will almost cease at the hot end of the HEN.

It is intended that the above measures will help the HEN 20 to heat the feedwater 28 to its critical temperature, with an amount of superheat sufficient to avoid water droplet formation upon entry to the primary oxy-combustor 12B.

After exit from part 20A of the HEN 20, the cooled exhaust stream E enters a two-stage condenser module 22, in which the exhaust stream is further cooled in the first stage heat exchanger/cooler 22A, which also acts as an initial stage of feedwater heating. Some water in the exhaust stream may be condensed out in the lower part of cooler 22A, but most water is condensed out as condensate 24 in the second stage heat exchanger/condenser 22B. Coolants 25 and 27 circulate through the cooler 22A and the condenser 22B, respectively. As shown, the coolant 25 may conveniently be the exhaust condensate 24, after it has passed through water treatment plant 26, thereby having lost further heat. Coolant 27 in condenser 22B may be water circulating to a so-called "fin-fan" heat exchanger which dumps the heat into ambient air. Alternatively, coolant 27 may be water from a local water source. The condensate 24 collects in the bottom of the condenser module 22, but most of the C0₂ remains above the water level and is extracted at 33 from the condenser module 22by a compressor (not shown), for subsequent transport and sequestration as liquefied gas.

From condenser module 22, the condensate 24 is passed through the previously mentioned water treatment plant 26 to remove particulates in suspension, and any dissolved gases and solids. The condensate 24 is treated in order to reduce or eliminate fouling and corrosion in the internals of the cooler 22 A, F£EN 20 and the turbine 16. Note that burning of hydrocarbon fuel with oxygen in the superheater 12 creates water of combustion as steam, which mixes with the steam already supplied to the superheater 12 to create a surplus of water, which is removed from the water treatment plant at 29.

After treatment, the condensate 24 is pumped by high pressure pump(s) 30 and recycled through cooler 22A as the feed-water supply 28 for the F£EN 20. A more accurate representation of the feedwater flow paths through the F£EN 20 is shown in Figure 5, but for purposes of illustration in Figure 1 the feedwater 28 is shown as divided into two streams before entering F£EN 20, one stream 31 being passed to part 20 A of F£EN 20 for heating by the turbine exhaust stream E, and the other stream 32 being passed to part 20B of F£EN 20 for heating by the turbine bleed streams PI to P3. As indicated by arrows, the feed-water repeatedly moves between parts 20A and 20B of F£EN 20, as at times it is heated by the bleed streams PI to P3 and at other times by the exhaust stream E, as further explained below.

After passing through the turbine bleed stream heat exchangers 20B, the bleed stream condensate 34 is added to the turbine exhaust stream E condensate 24 in condenser module 22, so that it can be purified for recycling, while the C0₂ left behind after condensation of the bleed steam is extracted from HEN 20 at 36 (e.g., by a compressor, not shown) to join the C0₂ extracted at 33 from condenser module 22.

Although Figure 1 indicates three turbine bleed streams PI to P3, the number of turbine bleed streams may be varied upwards from one, at the option of the system designer, taking into account design considerations applicable to particular cases. Thus, there may be a single high pressure bleed stream, taken from a high pressure stage in the turbine that may be, e.g., just after the first stage rotor blade 14A at a steam partial pressure of about half the critical pressure of steam during normal operating conditions of the cycle. Preferably, there may be several bleed streams, e.g., from two to five, taken in descending order of pressure and temperature from a corresponding number of stages of the turbine, the highest pressure bleed stream being taken from a stage in the turbine that is at the same pressure as would be the case if a single bleed stream were used. In addition to high pressure turbine bleed stream PI, taken immediately after the first stage moving blades 15 A, the embodiment of Figure 1 shows a medium pressure turbine bleed P2 being taken after the main flow exits of the high pressure turbine 16 A, but ahead of the reheat oxy-combustor 23. A lower pressure turbine bleed, P3, is taken from an intermediate point in the low pressure turbine 16B. The designations "high", "medium" and "low" pressure are of course relative to each other. In absolute pressure terms they are all high, due to turbine 16 being a critical pressure turbine.

The above high-level description of the oxy-combustion steam cycle system 10 will now be supplemented by a more detailed discussion of its most important component parts and their functions.

Primary and reheat oxy-combustors

As indicated diagrammatically in Figure 1, in the proposed oxy- fired superheater 12, steam from flow path 13 A is supplied to the primary oxy-combustion process via a turbine inlet box 12A, which is arranged within the turbine casing 16C to adjoin and enclose the combustor arrangement 12B, with the latter being close-coupled to the turbine inlet nozzles 14 A, which preferably comprise part of the box 12 A. The combustion process requires careful design because although the high pressures inherent in the present cycle aid efficient combustion, unburnt fuel and heat induced cracking of fuel can be problems in a closed cycle, such as proposed here. Such problems are further accentuated when to achieve the most efficient combustion, the aim is to have zero excess oxygen. Consequently, the present disclosure discusses alternative types of oxy-combustor arrangement applicable in Figure 1 to the primary oxy-combustor 12B of superheater 12 and to the reheat oxy-combustor 23. The embodiment of Figures 2 A and 2B is in principle preferred as applicable to both the primary oxy-combustor 12B and the reheat oxy-combustor 23, but is believed particularly applicable to the reheat oxy-combustor 23. The embodiment of Figure 2C is believed applicable to both the primary and re-heat oxy-combustors of Figure 1, but is believed particularly useful for replacing the embodiment of Figures 2 A and 2B as the primary oxy-combustor 12B if the inlet pressure to the primary oxy-combustor is not high enough to compress the combustion process into a space small enough to allow the use of the Figure 2A/2B embodiment.

The embodiment of Figures 2A and 2B is shown as applied to the primary oxy-combustor arrangement 12B and comprises a circular array of discrete combustion chambers 50 that are close-coupled to the high pressure turbine entry nozzles 14 A and are located within the turbine inlet box 12A acting as a plenum chamber, so that the steam can flow directly into the combustion chambers 50 without the need to channel it to the combustion process through ducts. The combustion chambers 50 act in parallel to direct the combustor efflux 57, essentially comprising superheated steam and C0₂, into the turbine entry nozzles 14 A. Igniters (not shown) need not be provided for each individual combustion chamber 50, provided ignition tubes 58, as known in gas turbine engines, are provided to promote light-around between the ignition zones 53 of circumferentially adjacent combustion chambers.

The combustion chambers 50 are analogous in construction to the combustion chambers already used in gas turbines for large combined cycle plant. In the illustrated embodiment, all the oxygen 0_2, a minor proportion of the steam 54 and a minor proportion of the gaseous hydrocarbon fuel HC are supplied to an ignition zone 53 through a burner 51 in the head of each combustion chamber 50. The relatively small amount of steam 54 that enters the head of the combustor, along with the fuel HC and oxygen 0₂, is intended to promote good mixing and local cooling. As will be explained in more detail below, most of the steam and fuel enters the combustion process after combustion has begun upstream in the combustor's ignition zone.

As seen in combustion chambers for gas turbine engines, the wall of each combustion chamber 50 is provided with plunge holes 52 distributed circumferentially over at least the mid-part of its axial extent. These plunge holes provide entry for steam jets from the inlet plenum chamber 12A as a diluent to the combustion process, as indicated by arrows 55. It may be advantageous for the jets of steam 55 that have entered through the plunge holes to be further subdivided into smaller jets. This may be achieved by providing the combustion chamber 50 with an inner combustion liner (not shown) provided with smaller holes through its radial thickness and throughout its axial and circumferential extent, though which the diluent steam could enter the combustion process. However, careful design would be necessary to avoid combustion occurring in the radial space between the combustion liner and the outer wall of the combustion chamber.

In an oxy-combustion steam cycle such as the present one, it is desirable that all the fuel gas is burnt, otherwise the steam and its condensate will be contaminated. Fortunately, in an oxy- combustion steam cycle there is more opportunity to improve combustion in comparison to a gas turbine cycle, because the oxygen and the steam diluent are separately sourced and independently controllable. In the present concept, it is envisaged that all the oxygen, a minor portion of the fuel (including carbon dioxide diluent if necessary), and a minor portion of diluent steam (i.e., enough of these to achieve the desired combustor temperature) are fed to the ignition zone 53 of the combustion chamber 50 through burner 51. The rest of the fuel may then be added progressively lengthwise and peripherally of the combustion process, where it can combine with the surplus oxygen delivered at the upstream end of the combustor. Note that this is very different from what happens in a normal gas turbine combustion process, where all the fuel and some of the air (oxygen) is added to the ignition zone and the remainder of the air, comprising oxygen needed to finish combustion of the fuel, and nitrogen as a diluent, is delivered later in the process.

In the present concept, it is desired to minimise or eliminate thermal cracking of the fuel, but this requires that the fuel must not be present in the combustion chamber until the moment of combustion. It is proposed here that such can be achieved by delivering the fuel into the chamber using the diluent steam as a carrier. The safest way of delivering the fuel into the carrier steam is to mix it with the steam as the steam enters the combustion chamber. One method of achieving this is indicated in dashed lines in Figure 2B, where the major portion of the fuel HC is delivered by means of a small diameter pipe 59 that spirals around the wall of the combustion chamber 50. The pipe 59 is provided with a number of small diameter holes (not shown), through which the fuel gas can flow onto the outer wall of the combustor by the Coanda effect and immediately mix with the diluent steam that is flowing over the outer wall of the combustion chamber 50 and into the combustion process through plunge holes 52. The oxy-combustion process superheats the steam to a high temperature i.e. circa 1450 deg. C, so that the turbine inlet nozzles 14 A operate at high temperature and pressure. However, because the feedwater has already been completely evaporated to steam, raised to at least its critical point and given some superheat by the HEN 20 before it enters the turbine inlet box 12 A, the main combustion process carried out in primary oxy-combustor 12B is used solely to add further superheat to the steam, thereby enabling the inlet box 12 A to operate at a steam inlet temperature of about 380 deg. C, i.e., about 1000 deg. C cooler than the main combustion process. This eases the constructional and cooling requirements of the inlet box 12 A.

It should be noted that in the present cycle, combustion in primary oxy-combustor 12B takes place at a pressure that is about ten times higher than the combustion pressure in a gas turbine; hence, the combustion process needs less room and the diffusion part of combustion will be a lot more rapid than in a gas turbine combustor. Additionally, the steam diluent is a lot hotter in the combustion process of the present cycle than the nitrogen diluent in a gas turbine combustion process, and this is a further aid to rapid combustion. Although combustion in reheat oxy-combustor 23 will take place at a lower pressure than that in primary oxy- combustor 12B, the pressure would be as high, if not higher, than in a gas turbine, so the space required for reheat oxy-combustor 23 is anticipated to be smaller, bearing in mind that the steam diluent would be much hotter than in combustor 12B. e.g., circa 650 deg. C. Hence, applying the embodiment of Figures 2A and 2B to the reheat oxy-combustor arrangement 23, the whole assembly would be contained within the outer, pressure-containing, casing of the turbine 16 and the high pressure turbine 16A would exhaust into a plenum chamber containing the combustion chambers 50, which would be close-coupled to the inlet nozzles 14B of the low pressure turbine 16B.

In another variant (not shown), instead of the circular array of angularly spaced-apart discrete combustion chambers 50 shown in Figures 2A and 2B, the combustor arrangement 12B may comprise a completely annular combustion chamber, in which the annular outlet of the combustion chamber is coupled directly to an annulus of turbine entry nozzles 14 A. A circular array of burners would inject oxygen and minor proportions of the fuel and steam into the combustion chamber, with most of the steam and fuel entering the combustion process downstream of the ignition zone, as previously described for Figures 2 A and 2B. This variant has the advantages of being more compact and of tending to even out temperature differences in the steam and gas impinging on the turbine inlet nozzles, which reduces thermally induced stresses in the turbine and is more thermodynamically efficient, as it enables the average turbine entry temperature to be slightly increased. Alternatively, essentially the same advantages may be achieved using two so-called "cannular" combustion chambers, in the shape of an upper combustion chamber and a lower combustion chamber, each one approximately comprising half of an annulus.

Even though the space required to house the primary oxy-combustor 12B is minimised by the high pressure at which it operates, the space occupied by the turbine inlet box 12 A containing oxy-combustor 12B needs to be minimised as the inlet box is contained within the turbine main pressure casing. For this reason, it is important to use the smallest combustor that is consistent with mechanical integrity and reliability. Hence, the oxy-combustor embodiment of Figure 2C may be better suited for use as the primary oxy-combustor 12B, instead of the Figure 2A/2B embodiment, or its variants with annular or cannular combustion chambers.

Figure 2C roughly illustrates the upper half of an oxy-combustor 180 comprising an upper combustion chamber 182, in the shape of a half toroid and a similar lower combustion chamber (not shown) arranged symmetrically with the upper combustion chamber 182 around horizontal centreline 184. Alternatively, the upper and lower combustion chambers could be of the cannular type, instead of semi-toroidal. An outer pressure containment wall 186 is a continuation of the outer casing of the HP turbine 16A (Figure 1) that lies behind the section shown in Figure 2C. Within casing 186 a wall 187 comprises a steam inlet box that surrounds the combustion chamber 182, inlet box 187 being effective to contain the critical pressure steam. A steam inlet duct 188, centred on vertical axis 190, is provided within a pressure containment casing 189 that is joined to turbine casing 186. Duct 188 carries superheated critical pressure steam 13A into the oxy-combustor 180. Within the steam inlet duct 188 and coaxial therewith is an oxygen supply pipe 192 that injects the total supply of oxygen 0₂ into a combustion ignition zone defined by a cylindrical wall 194 that is also coaxial with the steam inlet duct 188. The wall 194 of the ignition zone is joined to the top of the semi-toroidal or cannular combustion chamber 182, so that the ignition zone opens into the interior of the combustion chamber.

As was described above for the Figure 2A/2B embodiment, the preferred mode of combustion is to supply the ignition zone with all the required oxygen, but only relatively small amounts of fuel HC and steam 13 A, most of the fuel and steam being progressively introduced to the main combustion process that takes place in the cannular combustion chamber 182. At all times the fuel HC is introduced to the combustion process simultaneously with the diluent steam 13 A, and similarly to the Figure 2A/2B embodiment, this is achieved by providing plunge holes (not shown) in the peripheries of the ignition zone and the combustion chamber, so that jets of steam, signified by the small arrows 196, enter the combustion chamber 182 through the plunge holes, simultaneously entraining fuel gas HC that is released adjacent the plunge holes through small holes (not shown) in twin small diameter pipes 198 that spiral around the wall 194 of the ignition zone and the wall of the combustion chamber 182, as shown. The turbine inlet nozzles 14 A or 14B are located immediately behind the oxy-combustor arrangement shown in Figure 2C and superheated steam and combustion gases pass into the turbine inlet nozzles immediately after they exit the combustion chambers 182 through exhaust nozzles 199 located in the chamber walls between adjacent loops of the fuel pipes 198. The exhaust nozzles 199 are hidden in the view of Figure 2C and hence are indicated by dashed lines.

In a variant (not shown) of the Figure 2C embodiment, the ignition zone is located within the top of the combustion chamber 182 to avoid obstructing steam flow through steam inlet duct 188. In this case, the oxygen pipe 192 and the two fuel pipes 198 surrounding it would enter at the inner edge of the semi -toroidal or cannular combustion chamber, i.e., from the opposite direction to that shown in Figure 2C, directly in line with the inlet steam pipe As previously mentioned, with the necessary modifications, the embodiment of Figure 2C can also be applied to the reheat oxy-combustor 23, but it would not require an inlet box as the steam is no longer at a critical pressure. Although the above descriptions of the oxy-combustor embodiments have focussed on the desirability of supplying most of the fuel and steam in a metered manner downstream of the ignition zone, it might alternatively be possible to supply all the fuel to the ignition zone, together with minor proportions of the oxygen and steam, the remainder of the oxygen and steam being distributed peripherally and longitudinally of the oxy-combustion process downstream of the ignition zone, in this case using spiral tubes to distribute the oxygen. However, use of such a combustion mode is not presently preferred because it risks thermal cracking the fuel as it progresses through the combustion process, which would produce contaminating species of combustion products. As another alternative way of delivering fuel, oxygen and steam to the combustion process, it may be possible to put in all the oxygen and diluent steam at the upstream end of the combustor, the fuel being delivered separately to the ignition and combustion processes through ducts or the like. Whereas Figures 2A, 2B and 2C illustrate axially discharging combustion chambers, they may alternatively be arranged to discharge at an angle inclined to the axis of rotation of the turbine, or even radially, with suitable changes to the turbine layout.

Turbine and turbine nozzle construction

In comparison with known critical pressure steam turbines, the diameter of the turbine 16 in the present system is likely to be less than, but it's length more than, that of the FIP section of a critical pressure steam turbine, because it derives its power from a smaller steam flow.

For maximum thermal efficiency, the temperature of the combustion efflux at the turbine inlet nozzles 14 A and 14B (Figure 1) should be as hot as possible, consistent with the heat resistance of the materials available for making the nozzles, and assuming they are cooled using steam from the F£EN 20. Using readily available technology, this means that the maximum turbine nozzle entry temperature should be about 1450 deg. C, a similar temperature to that used in gas turbines of the type used in large combined cycle plant.

Regarding turbine 16, the high and low pressure turbines 16 A, 16B should each have an absolute pressure ratio between about 12: 1 to 14: 1 when measured from the inlet to the first nozzle to each of their exhausts. The high and low pressure turbines 16 A, 16B need not have the same pressure ratio if other considerations dictate otherwise.

It is proposed that turbine 16 should be a hybrid of current steam turbines and gas turbines. Although the turbine's nozzles and rotor blades may be similar to those of current gas turbines, it would require turbine casing strengths as currently found in a critical pressure steam turbine, i.e., stronger than found in current gas turbines. In addition to the turbine inlet nozzles 14, at least the initial stages of rotating and static blades will require cooling by steam. Assuming the steam raising process generates steam at or above its critical pressure, the high pressure turbine inlet nozzles 14 A should be designed to operate close to Mach 1, and therefore they will run approaching the choked condition and cause the steam and superheated efflux from the primary oxy-combustor to be evenly distributed to the combustors and the first turbine stage, respectively. However, if the steam is being generated below its critical pressure, the turbine inlet nozzles should run further below the choked condition, so that the pressure of the highest pressure turbine bleed stream is increased for more efficient operation of the HEN 20.

Heat exchange arrangements

The HEN 20 (Figure 1) functions as an unfired, "once through", critical pressure steam generator that raises steam by regenerative heat exchange of feedwater 28 with (i) the turbine exhaust stream E, and (ii) at least one turbine bleed stream PI to P3, preferably including a bleed stream PI taken from the high pressure end of the turbine 16 at, e.g., about half the critical pressure of steam. To maximise thermodynamic efficiency, the HEN 20 is designed to cool the turbine exhaust stream and the turbine bleed stream(s) close to the temperature of the exhaust steam condenser module 22, while simultaneously raising the temperature of the feedwater 28 from about 10 deg. C below the temperature of the exhaust condensate 24 up to (preferably) at least the critical temperature of the steam 13 before it is supplied to part 20 A and 20B of HEN 20 and then to the superheater 12 (note that the feedwater temperature is likely to be reduced below the exhaust condensate temperature by the water treatment plant 26). It follows from this that the condensing temperature of the turbine bleed steam determines a notional desired minimum temperature of the turbine exhaust stream, or vice-versa, the heat contribution from the turbine bleed stream(s) being taken into account. The skilled person will understand that the design of the turbine and the steam generator HEN 20 will be an interactive iterative process in accordance with the desired temperature of the turbine exhaust stream and the required pressure(s) of the turbine bleed stream(s). A heat balance calculation strategy for such design is disclosed later.

In the HEN 20, both sensible and latent heat is transferred to the feedwater, sensible heat being transferred to the feedwater from the turbine exhaust stream, the turbine bleed stream(s), and the condensates of the bleed streams, while latent heat of condensation is transferred to the feedwater from the turbine bleed steam. The necessity for such use of latent heat can be explained as follows.

The temperature of the turbine exhaust stream E before entering the HEN 20 is likely to be similar to that of the gas turbines used in large combined cycle plants, i.e., about 600 deg. C, but when used to raise steam, this would be insufficient on its own to evaporate all the feedwater, as previously mentioned. This is graphically illustrated in Figure 3, which plots temperature against enthalpy (heat quantity).

In Figure 3, the straight line S is a composite representation of the sensible heat supply available from the turbine exhaust stream E and the turbine bleed streams PI to P3. At the bottom of the temperature ordinate, the temperature Tc is the temperature of the condensate 24 in the exhaust condenser module 22. At the top of the temperature ordinate, temperature Tb is the maximum bleed stream temperature, which is likely to be about 1000 deg. C, and temperature Te is the normal turbine exhaust temperature of about 600 deg. C experienced during steady-state operation of the system 10, both temperatures being before entry to the HEN 20. Curve D, the heat demand curve, shows the heat required by the feedwater 28 to generate steam 13 for supply to the oxy-combustion process using the heat supply S available from the turbine exhaust. In effect, curve D is the temperature/heat content profile of the feedwater, which is the only heat sink, if losses to the environment are neglected. It is desired to bring the feedwater up to its critical point P at temperature Tp (about 374 deg. C) and then give it a modest amount of superheat to raise its temperature to Ts. Above the point I, where curve D intersects line S at a feedwater temperature Ti of about 320 deg. C, the heat demand can be entirely met by sensible heat from the turbine exhaust stream E and the turbine bleed streams. The contribution of sensible heat from the bleed and exhaust streams that is available to heat the feedwater 28 to the critical temperature Tp, is represented by the interval Te - Tc. It will be seen that below point I, the heat demand Di becomes greater than the heat supply Si, leading to an overall heat deficit H = Di - Si. Note that the generation of steam at a critical pressure minimises the heat deficit H and is one of the reasons why the HEN 20 should be operated as a critical pressure steam generator, the other reasons being respectively the desirability of a high pressure bleed PI from the turbine and the production of pressure drops in the turbine 16 sufficient to release the power contained in the high temperature flows of steam and carbon dioxide within the turbine.

Fig 3 not only indicates the overall size of the heat deficit H, but also the zone below the intersect I of curves D and S through which the heat deficit is distributed; i.e., the heat deficit continues down to the exhaust condenser temperature Tc, only part of the heat needed in this zone being supplied by the turbine exhaust and the sensible heat of the turbine bleed streams. The skilled person will appreciate that a higher exhaust temperature would lower the temperature at which the heat deficit H starts, and vice versa, so one way in which the heat deficit H could be reduced would be to raise the temperature of the turbine exhaust stream E. The simplest way of doing this would be to reduce the number of turbine stages, so the exhaust stream leaves the turbine 16 at a higher temperature. However, this is not an optimum solution to the problem of the heat deficit because if the deficit is reduced in this way, the cycle efficiency is also reduced. An alternative method of raising the exhaust temperature could be to raise the combustion temperature, but this solution is not favoured because it would require more expensive and/or shorter life turbine components. Additionally, higher turbine exhaust stream temperatures may also require more expensive exhaust containment materials in the HEN 20.

The above illustrates the need for a further source of heat to meet the heat deficit H for steam generation, and in the present concept the feedwater is heated by using the latent heat of decondensation of steam in the one or more turbine bleed streams, in conjunction with sensible heat from the turbine bleed stream(s), bleed steam condensate, and the turbine exhaust stream E. If only one turbine bleed stream is used to supply the heat deficit H, then steam at about half its critical pressure would be bled from the turbine immediately following the first, high pressure, stage of the turbine and used to supply the heat deficit by transferring sensible and latent heat to the feedwater in heat exchangers in HEN 20.

Although such a single high pressure turbine bleed stream may be sufficient to supply the heat deficit, thermodynamic efficiency is increased if several turbine bleed streams are taken in descending order of pressure. In theory, the highest cycle efficiency requires a bleed stream to be taken from each stage of the turbine between the highest and lowest turbine pressures, each such bleed stream being used to raise the temperature of the feedwater by a small amount. However, such an arrangement is impractical, so from the economic perspective, from two to five turbine bleed streams would probably be used. The illustrated embodiment assumes that three turbine bleed streams PI to P3 will be sufficient. From the point of view of designing the HEN 20, PI, P2 and P3 should ideally be taken at pressures of about 115 / 50 / 20 Bar-g, respectively, but from the point of view of designing the turbine 16, PI, P2 and P3 should preferably be taken at 115 / 15 / 4 Bar-g, respectively. A compromise may be required. The total turbine bleed stream flow is likely to be in the region of 25 - 30% of the total flow through the first stage of the turbine. For three turbine bleed streams the individual flows would be in the region of 10 to 12%, 8 to 10% and 6 to 8% of the total flow.

The skilled person will appreciate that in order to evaporate the feedwater to steam of at least critical temperature during operation of the cycle at differing operating conditions, it is necessary to balance the heat exchange process within the steam generator HEN. Such a heat balance can be achieved by controlling the mass flow rates of the turbine bleed streams. The exact mass flow rates of the turbine bleed streams may be determined by control loops which would adjust the flow rates of each bleed stream according to the contribution it is required to make to cancel out the heat deficit H and thereby achieve complete evaporation of the feedwater. Alternatively, it may well be the case that the bleed steam condensate flow-rate will automatically be self-regulating to the bleed stream pressures, which can be maintained by valves Vlr to V3r, as shown in Figure 5. Assuming a plurality of turbine bleed streams in descending order of pressure and temperature, there will be a plurality of heat exchangers, including some acting as condensers to extract the latent heat of condensation from the steam in the turbine bleed streams. Plainly, in order to raise the temperature of the feedwater 28 in appropriate increments from the temperature Tc at which it enters the HEN 20, it must receive heat from a bleed steam condenser that is at a low pressure and temperature, before it receives heat from condensers that are at a higher pressure and temperature.

Figure 4 illustrates, for the HEN 20 of Figure 1, how sensible and latent heat from the turbine bleed streams PI to P3 may be used to compensate for the heat deficit H noted in Figure 3. In Figure 4, the heat demand curve D is again shown on a graph of temperature against heat quantity. A composite heat supply curve S is superimposed on curve D and represents the combined heat inputs to the feedwater from the exhaust stream E and turbine bleed streams P3, P2 and PI . Upon exit from the turbine 16, bleed streams PI to P3 comprise superheated steam and C0₂, each bleed stream being at a different pressure, as explained previously. As will be described in more detail below, the turbine bleed streams PI to P3, by inputting to the feedwater their sensible heat above their condensation points, their latent heat of condensation, and the sensible heat of their condensates, assist the turbine exhaust stream E to raise the feedwater temperature significantly above temperature Ti at the intersect point I, to temperature Tp at the critical point P and even raise it by a few degrees of superheat to temperature Ts. Intersect point I corresponds to about 320 deg. C, the saturated temperature for steam at a pressure of about 115 bar-g, i.e., approximately the pressure of the highest pressure turbine bleed stream PI . Comparing Figure 1 with Figure 4, the turbine bleed stream heat above the turbine exhaust stream exit temperature Te is used to raise the feedwater steam from its temperature Tp at the critical point P, up to a temperature Ts, representing a few degrees of superheat for the feedwater steam. The heat contributions of the turbine bleed streams above temperature Te are Pls+P2s+P3s, represented by the part SI of heat supply curve S, the "s" suffix representing the sensible heat contribution of the bleed streams to the superheat component of the heat demand curve D. This superheat contribution from the bleed streams is transferred to the feedwater steam indirectly by using the bleed streams to heat the exhaust stream E in part 20A of the HEN 20, then using this added heat in the exhaust stream E to superheat the evaporated feedwater before it finally leaves HEN 20 as superheated steam 13 A. This process is approximately indicated in Figure 4 by the diagram in dashed lines to the right of heat supply line S2, which will be further discussed in relation to Figure 5. It follows from the above that part 20B of F£EN 20 heats feedwater 32 using only heat from bleed steam that has been cooled to below the exit temperature Te of the turbine exhaust E, while part 20A of F£EN 20 heats feedwater using heat from the exhaust stream E, plus heat from bleed steam above temperature Te. In Figure 4, the sensible heat contributions Pl+P2+P3+Elof the turbine exhaust stream E and the turbine bleed streams between temperatures Ti and Te as they are cooled down to the intersect point I, are represented by the part S2 of composite supply curve S , whereas the parts of the composite curve S below intersect point I represent heat supplied to the feedwater by a combination of sensible heat from the exhaust stream E and the turbine bleed streams PI to P3, plus latent heat of condensation supplied by the turbine bleed streams.

Thus, the arcuate portions HI to H3 of the lower part of the heat supply curve SI, below point I, represent heat contributed to the feedwater through heat exchangers supplying heat from condensation of the turbine bleed streams PI to P3, respectively, combined with sensible heat contributed to the feedwater by: (i) the exhaust stream E; (ii) the bleed streams as they are cooled from temperature Te to their saturation temperatures; and (iii) the condensates of the bleed streams. These latent and sensible heat contributions raise the feedwater temperature from the exhaust condenser temperature Tc up to temperature Ti.

Figure 5 diagrammatically illustrates a network of heat exchangers comprising the HEN 20, arranged to supply heat to the feedwater in the manner represented in Figure 4, and therefore suitable for use when there are three turbine bleed streams PI to P3 in addition to the turbine exhaust stream E. As indicated in Figure 5, HEN 20 includes six heat exchange stages HI to H6. For maximum heat exchange efficiency the feedwater 28 flows through the heat exchange stages in a direction that is counter to the direction of flow of the turbine exhaust stream E and the turbine bleed streams PI to P3. Explaining the layout and graphic conventions used in Figure 5:-

• Heat exchangers are represented by dashed lines, with the directions of heat flow indicated by arrow heads in the dashed lines.

• In heat exchange stages HI to H4 and H6, the horizontal parallel lines represent sub- streams of either the feedwater stream 28 or the exhaust stream E, as the case may be, each sub-stream being dedicated to receiving heat from a donor stream through a particular heat exchanger, as shown. Consequently, each sub-stream is heated in parallel with the other sub-streams of the same heat exchange stage.

• The vertical line joining up the horizontal lines on the right hand side of each heat exchange stage HI to H4, or the left hand side of stage H6, represent division of the feedwater stream 28, or exhaust stream E, into the sub-streams of each stage.

• The vertical lines on the left hand side of each heat exchange stage HI to H4, or the right hand side of stage H6, represent bringing together of the sub-streams - which have been separately heated to a common temperature - into a single stream, ready for further heat exchange in an adjacent heat exchange stage.

• Heat exchangers associated with each heat exchange stage are referenced by the number of the heat exchange stage, e.g., HI, followed by a number allocated to the heat exchanger based on the particular sub-stream with which the heat exchanger communicates; e.g., Hl/1 is the heat exchanger that communicates with the "lowest" feedwater stream in heat exchange stage 1, whereas H4/5 is the heat exchanger that communicates with the "highest" feedwater stream in heat exchange stage 4.

• Heat exchangers H3/4, H2/5, Hl/5, H2/4, Hl/4 and Hl/3act as condensers for turbine bleed streams PI to P3 and therefore produce streams of condensate CI a, Clb, Clc, C2a, C2b and C3a. These condensates accumulate in sumps associated with each condenser, the outputs of which are controlled by sump water level (L) actuated valves Via, Vlb, etc., signal paths being represented by the dotted lines. C0₂ left behind in the condenser sumps is extracted for sequestering, as previously mentioned.

• Also shown in Figure 5 are pressure (p) actuated valves Vlr, V2r and V3r, which control the pressure in each turbine bleed stream PI, P2, P3, respectively, by acting on the outlets for the residue of each bleed stream. It will therefore be appreciated from Figure 5 that feedwater 28 receives heat from a plurality of heat donor streams, these being the turbine exhaust stream E, the three turbine bleed streams PI to P3, and streams of condensate produced by condensation of the turbine bleed streams in condensing heat exchangers H3/4, etc.

The F£EN 20 may thus be thought of as a plurality of heat exchange stages HI to H6 arranged sequentially to input heat to the feedwater in ascending order of feedwater temperature, wherein:

(a) at heat exchange stage HI, latent heat from condensation of turbine bleed streams PI, P2 and P3 is input to the feedwater, together with sensible heat from the condensates of turbine bleed streams PI and P2;

(b) at heat exchange stage H2, latent heat from condensation of turbine bleed streams PI and P2 is input to the feedwater, together with sensible heat of the turbine bleed stream P3 above its condensation temperature, but below exit temperature Te of the turbine exhaust stream, and sensible heat from the condensate of turbine bleed stream

PI;

(c) at heat exchange stage H3, latent heat from condensation of turbine bleed stream PI is input to the feedwater, together with sensible heat of the turbine bleed streams P2 and P3 above their condensation temperatures, but below the exit temperature Te of the turbine exhaust stream;

(d) at heat exchange stage H4, sensible heat of the turbine bleed streams PI to P3 above their condensation temperatures, but below the exit temperature Te of the turbine exhaust stream, is input to the feedwater;

(e) at a heat exchange stage comprising in this case a combination of stages H5 and H6, sensible heat of the turbine bleed streams PI to P3 above the exit temperature Te of the turbine exhaust stream, is input to the feedwater steam;

and wherein, in each of the heat exchange stages HI to H5, sensible heat from the exhaust stream E is input to the feedwater/steam, and in each heat exchange stage having a plurality of heat inputs, all heat inputs are made in parallel with each other.

It should be remembered that any C0₂ content of the bleed streams PI to P3 will also contribute sensible heat inputs to the feedwater/steam through condensing and non-condensing heat exchangers. However, any heat contribution from C0₂ dissolved in the condensate streams will be minimal. Furthermore, any steam which is not condensed in a particular condenser will also contribute sensible heat to the feedwater through that condenser.

Working from left to right in Figure 5, during normal operation of the HEN 20 when the turbine 16 is working at full load, a final few degrees of superheat are imparted to the feedwater steam by the interaction of heat exchange stages H4 to H6, as follows :-

(i) An amount of sensible heat Ql is transferred through heat exchanger 4/1 from the exhaust stream E to a corresponding feedwater stream in heat exchange stage H4. This is indicated in Figure 4 (with reference to the total enthalpy of the exhaust stream) by the horizontal dashed line labelled H4/1.

(ii) In heat exchange stage H6, amounts of sensible heat Q2, Q3, and Q4 are transferred from superheated turbine bleed streams PI, P2 and P3, through heat exchangers H6/1 to H6/3, respectively, into corresponding exhaust sub-streams in heat exchange stage H6. The effect on the total enthalpy of the exhaust stream is indicated in Figure 4 by the upward arrow H6 in the inclined dashed line on the extreme right. Neglecting losses,

Ql≤ Q2+Q3+Q4. Heat amounts Q2, Q3, and Q4 added into the exhaust stream E are those parts of the superheat in the corresponding bleed stream that are above the turbine exhaust exit temperature Te.

(iii) In heat exchange stage H5, added heat Q2+Q3+Q4 in the exhaust stream E is transferred to the feedwater steam through the heat exchanger H5/1. The effect on the enthalpy of the exhaust stream is indicated in Figure 4 by the downward arrow H5 in the inclined dashed line on the extreme right. In this way, high grade heat Q2+Q3+Q4 from steam in the turbine bleed streams that is above temperature Te, is indirectly used to heat a portion 13 of the evaporated feedwater from heat exchange stage H4, thereby producing superheated steam 13 A for use in the superheater 12 (Figure 1).

The above indirect method of using the turbine bleed streams PI to P3 to superheat the feedwater steam is less thermodynamically efficient than using the bleed streams to heat the feedwater steam directly, but is still effective to enhance the thermodynamic efficiency of the cycle by reducing the amount of fuel needed for burning in the superheater 12. It should be understood that the sole reason for adopting this indirect heating method in the present embodiment is to reduce CAPEX costs associated with use of more expensive materials and construction techniques in the heat exchangers at the hot end of the HEN20. Hence, in heat exchange stages H5 and H6, the mechanical design and cost of the heat exchangers H5/1 and H6/1 to H6/3 are eased, because one side of each heat exchanger is situated in duct 21, similarly to well-known types of heat exchangers used in gas turbine exhaust ducts. Furthermore, heat exchanger H4/1 is included in Figure 5 solely to lower the temperature of the exhaust stream E before it enters heat exchange stage H6, so that the parts of the heat exchangers in contact with the turbine exhaust do not have to be made of more expensive materials in order to cope with the heat Q2+Q3+Q4 added into the exhaust E from the turbine bleed streams. However, it should be understood that, neglecting mechanical and CAPEX considerations, heat exchange stages H5 and H6, and heat exchanger H4/1, could be replaced by a single, final heat exchange stage dedicated to transferring heat directly to the feedwater steam 13 from the turbine bleed streams PI to P3.

Again referring heat exchange stage H4 to the graph in Figure 4, it can be seen that heat exchangers H4/2 to H4/5 contribute the heat represented by the lower part of the inclined line S2.

The horizontal distance X in Figure 4 represents the heat contribution of the bleed streams PI to P3 below the turbine exhaust temperature Te and in the same temperature zone as exhaust cooling line E2.

As previously described in connection with Figure 1, a supplementary oxy-combustor 17 is located immediately after heat exchange stage H4 to selectively input heat to the steam flow 13, if such is required in order to complete evaporation of the feedwater 28 to at least its critical temperature.

Cycle heat balance

The calculations for the performance of the cycle, taking into account all the heat and power flows, may be under-taken in the form of an "exergy" analysis for the best optimisation of the cycle. The calculation is iterative, due to the interaction of the turbine and F£EN performance. A normal thermal analysis for the F£EN 20 embodiment in Figures 1, 4 and 5 is outlined below. 1. Assumptions

1.1 Choose a feedwater flow-rate to determine the power output and the efficiency of the cycle, e.g., 300Kg/s would give a power output in the range of a single unit in a power station. This can be adjusted later if the power output is not the desired amount. 1.2 Select a steam generation pressure which is as low as possible (say, 250 Bar-g.), but which is sufficiently above the minimum critical pressure so that the addition of fuel and oxygen to the steam 13 A still results in the steam's partial pressure being in excess of the minimum critical pressure, while also allowing for pressure loss in the primary oxy-combustor 12B. The partial pressure of the carbon dioxide should initially be assumed as 8% of the total pressure in the primary combustor 12B when starting calculations in the HEN. (N.B., the reheat oxy-combustor 23 contains circa 12% carbon dioxide)

1.3 Initially assume the PI bleed conditions are 105 Bar-g/950 deg. C/8% C0₂ by volume*.

1.4 Initially assume the P2 bleed conditions are 35 Bar-g. /700 deg. C/8% C0₂ by volume.*

1.5 Initially assume the P3 bleed conditions are 8 Bar-g/750 deg. C/12% C0₂ by volume. * 1.6 Initially assume the turbine exhaust conditions are 1.04 Bar-g. /650 deg. C/12% C0₂ by volume.

*Note that the bleed stream saturation temperatures can be identified for these assumed conditions.

In subsequent iterations all the assumptions are replaced by calculated values. 2. Make the first calculation for the primary combustor, assuming the steam supplied to it has no super-heat and that the steam and combustion products generated are heated to 1450 deg. C.

3. Make the first calculation for the reheat combustor 23 using the assumed conditions at the reheat combustor inlet for the P2 bleed. The flow-rate is that from the primary combustor assuming 10% is lost to the PI bleed and 8% is lost to the P2 bleed. The steam generated and combustion products are to be heated to a temperature of 1450 deg. C.

4. Calculations for the HEN 20 in respect of the Te to Ti range of temperatures may now start. Using the assumed turbine exhaust temperature Te and assuming the flow-rate is that leaving the primary combustor 12B, i.e., neglecting any reduction due to bleed flows, calculate the heat supply between Te and Ti. (This assumption is made for the initial calculation as there is not too much difference in the specific heat of the turbine exhaust and the bleed streams). Next, calculate the feedwater heat demand between temperatures Tp and Ti. When calculated turbine exhaust and bleed flow pressures and compositions are known, then these may be used to obtain the most accurate value of heat supply.

4.1. If the heat supply exceeds demand then the exhaust temperature can be lowered by the appropriate amount. Should an exhaust temperature of 650 deg. C. not supply sufficient heat, then part of the bleed heat above 650 deg. C may be used to balance the heat supply with the heat demand. 5. Calculations for the HEN 20 below temperature Ti may now start.

5.1 Calculations to determine the high pressure PI bleed stream flow rate may now start. Having calculated the saturation temperature for the P2 bleed stream, the heat demand between the two upper bleed condensation temperatures may now be calculated. Assume initial values of bleed stream flows, i.e. P2 is 8% of the total flow from the exit of the primary combustor and P3 is 5% of the total flow from the reheat combustor. The turbine exhaust flow-rate should be assumed as 95% of the reheat combustor output. Using this information, the heat supplied between the onset of condensation temperatures for PI and P2 can be calculated for all the participating streams, except for the PI bleed stream. These contributions are purely of sensible heat. After this, the heat contribution per unit mass of the PI bleed stream may then be calculated, taking account of both sensible heat and latent heat. Sensible heat needs to take account of steam condensate as well as that of the steam and carbon dioxide. Once the heat deficit for this stage in the cycle is known, the mass flow-rate of the PI bleed stream can be calculated and should be used in subsequent calculations until further iterations change its value. 5.2 Calculations to determine the P2 bleed stream flow rate required may now start. The calculations proceed in a similar manner to that above, except that the PI bleed flow will still contain some steam, part of which will condense in this stage of the cycle, as well as most of the P2 bleed steam. The heat supplies from the exhaust, the P3 bleed stream and the remaining calculated PI bleed stream flow, along with that of its condensate, are then calculated. The heat demand between the P2 and P3 onset condensation temperatures is then calculated. The difference between the demand and the supply, excluding the P2 steam, may then be determined. After this, the heat supply per unit mass of P2 steam within the stage may then be calculated, enabling the required mass flow-rate of the P2 steam to be calculated. As the PI and P2 bleed condensates are now at the same temperature they may be merged (see Figure 5) and contribute to the heat supply of the next stage. 5.3 Calculations to determine the P3 bleed stream flow rate required may now start. All the streams are now to be cooled to the onset of the condensation temperature of the exhaust stream. (Note, the feedwater supplied to the HEN 20 is assumed to enter it 10 deg. C lower than the onset of the turbine exhaust's condensation temperature) Knowing this, the calculations proceed in a similar manner to that above, except that the PI and P2 bleed flows still contain some steam, part of which will condense in this stage of the cycle, as well as most of the P3 bleed steam. The sensible heat in the combined condensate from the PI and P2 streams should also be added to the heat supply calculations. The heat demand between the onset of the condensation temperatures of the P3 bleed and the turbine exhaust may then be calculated. Knowing the heat demand and the supply, except for the P3 bleed stream, the heat deficit may then be calculated. The heat supply per unit mass of P3bleed flow may then be calculated, from which the total P3 bleed flow is calculated. As all the steam condensate flows are now at the same temperature, they may be merged for water treatment, as in Figure 1.

5.4 Calculations to determine the amount of super-heat available from the bleed streams above the exhaust temperature may now be made. Having obtained the first calculated values of the PI, P2 and P3 bleed streams, and having assumed values of their supply temperature, the heat content of these streams above the exhaust temperature may now be determined. From this the steam temperature and enthalpy supplied to the primary combustor may now be calculated.

6. Having reached this point in the calculations, the first turbine calculations may now be made, from which more precise bleed conditions may be obtained. The calculations for the HEN 20 may then be repeated, but with more accurate information. Convergence for the overall cycle calculation is rapid.

Determination of optimum number of turbine bleed streams

The above description of how to calculate the performance of the HEN 20 assumes that there will be three turbine bleed streams, this being the most likely choice for a system having both primary and reheat combustors. This is because the medium pressure P2 bleed stream may be extracted immediately ahead of the reheat combustor, leaving only one bleed stream required from the HP turbine and one bleed stream required from the lower pressure turbine. To begin determination of the optimum number of bleed streams, a next higher or lower number of bleed streams would need to be designed for, with the cost of bleed steam provision and capital cost calculated. In this way the cost effectiveness of increasing or decreasing the number of bleed streams may be calculated according to whatever financial criteria is used for a given project. Once the optimum number of bleed streams has been decided, the optimisation of using larger temperature zones at lower temperature levels may be calculated.

Operation of the cycle using steam at sub-critical pressures.

Although the above description has focussed on using regenerative heating in the HEN to raise steam to at least its critical point, due to the thermal efficiency benefits obtained by doing so, it would be possible to operate the cycle using a steam generating pressure below the critical point. This is because, for any given turbine exhaust temperature and amount of superheat in a turbine bleed stream, there is a minimum bleed stream condensing temperature required for heat balance purposes. Therefore, if steam is generated at a lower pressure, a lower steam pressure loss in the first stage of the turbine would be required to maintain the desired condensing temperature.

Reasons for operating the cycle using a steam generating pressure below the critical point could be to reduce the capital cost of the plant, or to ease design of the pressure containment or steam turbine parts of the system. Nevertheless, the techniques for designing for such conditions are already known, and the reduced operating cost of a system designed for critical pressure steam would more than justify the additional capital cost. Sub-critical operation should therefore be avoided if possible.

Exhaust steam condenser module 22

The exhaust steam condenser module 22receives the turbine exhaust stream E after the latter has passed through the HEN 20 and supplies condensate for recycling through the HEN as feedwater 28, the latter also including condensate 34 from the turbine bleed steam. When steam generated by the HEN 20 leaves the oxy-fired superheater 12, it is mixed with carbon dioxide and steam derived from the combustion process. Note that the presence of carbon dioxide with the steam results in the steam's partial pressure being a little lower than the total pressure in the combustor, and at all points downstream of the combustor. Consequently, the steam's condensation temperature will also be a little lower. When the turbine exhaust stream E reaches the exhaust steam condenser module 22, the carbon dioxide is left behind therein, together with a small amount of steam. This enables it to be extracted, along with the carbon dioxide collected from the bleed streams, for compression and transmission to a suitable geological structure for storage. It should be understood that the pressure in the turbine exhaust condenser module 22 has an influence on the efficiency of the cycle for the following reasons:

• A low exhaust condenser pressure increases the amount of power required to extract the carbon dioxide for onward transmission.

• A low exhaust condenser pressure results in a lower condensate temperature, thereby requiring more turbine bleed steam heat to assist evaporation of the steam generator feedwater. This may even require an additional turbine bleed stream to be incorporated in the design.

On the other hand, a benefit arises in that a low condenser pressure provides more pressure drop for releasing power in the turbine 16, and with a system like Figure 1 that has both primary and reheat combustors 12B and 23, this consideration is likely to be important. Use of significantly higher exhaust pressures is therefore likely to be restricted to systems having only a primary combustor 22B and a supplementary combustor 17.

It is likely that the optimum exhaust condenser pressure will be slightly above atmospheric pressure, similar to known gas turbines that have primary and reheat combustors, so making the plant suitable for operation in hot climates without loss of power output or efficiency, while using atmospheric air as the heat sink for the exhaust condenser 22B. Another benefit of having an exhaust condenser pressure slightly above atmospheric pressure is that ingress of ambient air to the cycle will be prevented.

Although the above description has focussed on the desirability of using a high pressure turbine bleed stream to input heat to the feedwater, it would be possible to replace it with other heat sources. For example, if for a particular turbine it is difficult for mechanical reasons to extract a bleed stream from the high pressure turbine stages, it would be possible to take a small proportion of the critical pressure steam produced by the steam generator HEN 20 and to superheat it sufficiently so that when its pressure is reduced upon entry to the reheater oxy- combustor 12B, no steam condensate is formed. The heat required for superheating the steam taken from the HEN 20 can come from one or more other bleed streams while they are hotter than the turbine exhaust. If their heat is not sufficient for this task, the cycle heat balance can be restored by a small increase in the turbine exhaust temperature. This expedient would have only a small effect of the cycle efficiency.

Another possibility is to replace the high pressure turbine bleed heat with heat rejected from an air separation unit used to supply oxygen to the superheater 12 and the reheater 23. This heat rejected by the ASU would be input it to the feedwater through the HEN 20, thereby also increasing the efficiency of the cycle.

This steam power cycle and its implementing systems have been described above purely by way of example, and modifications can be made within the scope of the appended claims.

Any discussion of the prior art throughout the specification is not an admission that such prior art is widely known or forms part of the common general knowledge in the field.

Unless the context clearly requires otherwise, throughout the description and the claims, the words "comprise", "comprising", and the like, are to be construed in an inclusive as opposed to an exclusive or exhaustive sense; that is to say, in the sense of "including, but not limited to".

Claims

1. A method of operating a steam power cycle, comprising the steps of:

(a) supplying a superheating oxy-combustion process [12B] with fuel [HC], oxygen [0₂] and steam [13 A], the steam being supplied as a diluent to the combustion process;

(b) driving a steam turbine arrangement [16] with superheated steam and combustion products produced by the oxy-combustion process thereby to produce power from the cycle;

(c) evaporating feedwater [28] in a steam generator [20] by regenerative heat exchange with a turbine exhaust stream [E] and at least one turbine bleed stream [PI, P2, P3], wherein the turbine exhaust stream gives up sensible heat to the feedwater and each turbine bleed stream gives up sensible heat and latent heat of condensation to the feedwater;

(d) producing the feedwater for the steam generator by condensing steam from the turbine exhaust stream and combining the resulting condensate [24] with condensate [34] from the at least one turbine bleed stream; and

(e) recycling the feedwater through step (c) and passing it to step (a).

2. A method according to claim 1, comprising the steps of reheating the products of the superheating combustion process after said products have passed through a higher pressure turbine and discharging said reheated combustion products into a lower pressure turbine, said reheating comprising a second oxy-combustion process supplied with fuel and oxygen.

3. A method according to claim 1 or claim 2, comprising the step of raising the evaporated feedwater to at least its critical point by said regenerative heat exchange.

4. A method according to any preceding claim, comprising the step of extracting carbon dioxide from the cycle when steam from the turbine exhaust stream and each turbine bleed stream is condensed.

5. A method according to claim 3 or claim 4, comprising the step of supplying steam to the superheating oxy-combustion process at a pressure sufficiently above the steam's critical pressure, and with sufficient superheat, to obviate condensation of steam due to reduction of the steam's partial pressure upon entry to the superheating oxy-combustion process.

6. A method according to any preceding claim, comprising the step of supplying fuel as one of the following: a hydrocarbon gas, hydrogen, carbon monoxide.

7. A method according to claim 6, comprising the step of diluting the fuel with carbon dioxide to temper the oxy-combustion process.

8. A method according to any preceding claim, comprising the step of supplying minor proportions of steam and fuel to an ignition zone of the combustion process, together with enough oxygen to burn all the fuel admitted to the combustion process.

9. A method according to claim 8, comprising the step of distributing major proportions of steam and fuel peripherally and longitudinally of the oxy-combustion process downstream of the ignition zone, the steam entering the combustion process as a diluent and the fuel being carried into the combustion process by the diluent steam.

10. A method according to claim 9, comprising the step of releasing the fuel gas into the diluent steam as the steam enters the combustion process.

11. A method according to any preceding claim, comprising the steps of admitting the steam to the superheating combustion process via a steam inlet box of the turbine and discharging the combustion products directly into inlet nozzles of the turbine.

12. A method according to any preceding claim, comprising the step of taking at least one turbine bleed stream from a high pressure turbine stage.

13. A method according to claim 12, comprising the step of taking a plurality of turbine bleed streams in descending order of pressure from a corresponding plurality of turbine stages comprising a high pressure stage and at least one lower pressure stage.

14. A method according to claim 12 or claim 13, comprising the step of taking a turbine bleed stream from a high pressure turbine stage at a partial pressure of about half the critical pressure of steam.

15. A method according to any one of claims 12 to 14, comprising taking between two and five separate bleed streams from turbine stages at different pressures.

16. A method according to claim 15, comprising the steps of taking a high pressure bleed stream, a medium pressure bleed stream and a low pressure bleed stream from corresponding turbine stages.

17. A method according to any preceding claim, comprising the step of condensing steam from the turbine exhaust stream using atmospheric air as a heat sink.

18. A method according to any preceding claim, comprising the step of condensing steam from the turbine exhaust stream at about atmospheric pressure or above.

19. A method according to any preceding claim, comprising the step of raising the feedwater temperature from at or below its condensation temperature to at least its critical temperature by means of regenerative heat exchange in a heat exchange network comprising a plurality of heat exchange stages arranged sequentially to input heat to the feedwater in ascending order of feedwater temperature.

20. A method according to claim 19, comprising the steps of transferring to the feedwater:

(b) latent heat of condensation of the bleed steam;

(c) sensible heat of the bleed steam condensate; and

(d) sensible heat of the turbine exhaust before it has cooled down to its condensation temperature.

21. A method according to claim 20, comprising the steps of:

(a) converting feedwater to steam at critical pressure and temperature by using a combination of (i) latent heat from condensation of the turbine bleed steam, (ii) sensible heat from the turbine exhaust stream, (iii) sensible heat from turbine bleed stream(s) below the turbine exhaust exit temperature, (iv) sensible heat from turbine bleed steam condensate; and (b) raising feedwater steam temperature from the critical temperature to a superheat temperature using sensible heat from turbine bleed stream(s) above the turbine exhaust exit temperature.

22. A method according to any one of claims 19 to 21 as dependent from claim 16, comprising the steps of:

(a) in a first stage of heat exchange, inputting latent heat from condensation of all three bleed streams to the feedwater, together with sensible heat from the condensates of the high and medium pressure bleed streams;

(b) in a second stage of heat exchange, inputting latent heat from condensation of the high and medium pressure bleed streams to the feedwater, together with sensible heat from the low pressure bleed stream above its condensation temperature, but below the turbine exhaust exit temperature, and sensible heat from condensate of the high pressure bleed stream;

(c) in a third stage of heat exchange, inputting latent heat from condensation of the high pressure bleed stream to the feedwater, together with sensible heat from the low and medium pressure bleed streams above their condensation temperatures, but below the turbine exhaust exit temperature;

(d) in a fourth stage of heat exchange, inputting to the feedwater sensible heat from the high, medium and low bleed streams above their condensation temperatures, but below the turbine exhaust exit temperature;

(e) in a fifth stage of heat exchange, inputting to the feedwater sensible heat from the high, medium and low bleed streams above the turbine exhaust exit temperature;

wherein, in each of the above heat exchange stages, sensible heat from the turbine exhaust stream is also input to the feedwater.

23. A method according to claim 21 or 22, comprising the steps of first adding the bleed stream heat above the turbine exhaust exit temperature to the turbine exhaust stream and then transferring the added heat in the turbine exhaust stream to the feedwater.

24. A method according to any one of claims 19 to 22, comprising the step of making each heat input at each stage of heat exchange in parallel with all other heat inputs to the same stage.

25. A steam power system comprising:

(a) a superheater comprising an oxy-fired combustor arrangement for burning gaseous fuel with nominally pure oxygen in an oxy-combustion process with steam as a diluent to the combustion process;

(c) a steam generator for evaporating feedwater by regenerative heat exchange with a turbine exhaust stream and at least one turbine bleed stream, wherein the turbine exhaust stream gives up sensible heat to the feedwater and each turbine bleed stream gives up sensible heat and latent heat of condensation to the feedwater; and

(d) condensing heat exchangers for condensing steam from the turbine exhaust stream and the at least one turbine bleed stream, the resulting condensates being combined to produce feedwater for recycling through the steam generator, thereby to produce the diluent steam for the oxy-combustion process.

26. A steam power system according to claim 25, provided with a reheater comprising a second oxy-combustion arrangement provided with inputs for nominally pure oxygen and fuel.

27. A steam power system according to claim 26, in which the reheater is located between a high pressure turbine and a low pressure turbine of the steam turbine arrangement to reheat the efflux of the high pressure turbine.

28. A steam power system according to any one of claims 25 to 27, in which the steam generator is arranged to raise evaporated feedwater to at least its critical point by said regenerative heat exchange.

29. A steam power system according to any one of claims 25 to 28, in which the condensing heat exchangers are adapted to allow extraction of carbon dioxide from the cycle when steam in the turbine exhaust stream and each turbine bleed stream is condensed therein.

30. A steam power system according to claim 28 or claim 29, in which the steam generator is arranged to supply steam to the superheater at a pressure sufficiently above the steam's critical pressure, and with sufficient superheat, to obviate condensation of steam due to reduction of the steam's partial pressure upon entry to the oxy-combustion process.

31. A steam power system according to any one of claims 26 to 30, wherein the superheater and the reheater are each capable of burning one of a hydrocarbon gas, or hydrogen, or carbon monoxide.

32. A steam power system according to any one of claims 25 to 31, in which the superheater comprises a steam inlet box containing the oxy-fired combustor arrangement.

33. A steam power system according to claim 32, in which turbine entry nozzles are attached to an exit face of the steam inlet box.

34. A steam power system according to claim 32 or claim 33 as dependent on claim 28, in which the steam inlet box is adapted to contain steam raised to at least its critical pressure by the steam generator.

35. A steam power system according to any one of claims 32 to 34, in which the steam inlet box is contained within a pressure casing of the steam turbine arrangement.

36. A steam power system according to any one of claims 26 to 35, in which the second oxy-combustor arrangement is contained within a pressure casing of the steam turbine arrangement.

37. A steam power system according to any one of claims 25 to 36, in which oxy-fired combustor arrangements comprise one of (i) a circular array of discrete combustion chambers, (ii) two cannular combustion chambers comprising upper and lower half-annular combustion chambers, (iii) a fully annular combustion chamber.

38. A steam power system according to any one of claims 25 to 36, in which oxy-fired combustor arrangements comprises one of (i) upper and lower semi-toroidal combustion chambers; (ii) upper and lower semi-annular combustion chambers; the combustion chambers being arranged to receive oxygen, fuel and air through ducts centred on a vertical axis.

39. A steam power system according to claim 37 or claim 38, in which outlets of the combustion chambers are close-coupled to turbine entry nozzles.

40. A steam power system according to any one of claims 37 to 39, in which the combustion chambers are provided with burners for supplying ignition zones of the chambers with all the oxygen necessary for combustion, a minor proportion of the diluent steam and a minor proportion of the fuel; the combustion chambers being adapted to distribute the rest of the fuel and steam longitudinally and peripherally of the combustion process to combine with oxygen not burnt during ignition.

41. A steam power system according to claim 40, in which portions of the combustion chambers surrounding the combustion process are provided with plunge holes for admitting jets of steam to dilute the combustion process, fuel being delivered to the combustion process mixed with the steam.

42. A steam power system according to claim 41, having ducts around combustion chamber outer surfaces through which fuel is distributed to the combustion process downstream of the ignition zone, the ducts having small exit holes through which fuel can flow onto said outer surfaces by the Coanda effect and immediately mix with diluent steam flowing through the plunge holes.

43. A steam power system according to any one of claims 25 to 42, having at least one turbine bleed stream taken from a high pressure turbine stage of the steam turbine arrangement.

44. A steam power system according to claim 43, having a plurality of turbine bleed streams taken in descending order of pressure from a corresponding plurality of turbine stages comprising a high pressure stage and at least one lower pressure stage.

45. A steam power system according to claim 43 or claim 44, in which in operation a turbine bleed stream is taken from a high pressure turbine stage at a partial pressure of about half the critical pressure of steam.

46. A steam power system according to any one of claims 43 to 45, in which between two and five separate bleed streams are taken from turbine stages at different pressures.

47. A steam power system according to claim 46, in which a higher pressure bleed stream, a medium pressure bleed stream and a lower pressure bleed stream are taken from corresponding turbine stages.

48. A steam power system according to any one of claims 25 to 47, in which a condenser module condenses steam from the turbine exhaust stream using atmospheric air as a heat sink.

49. A steam power system according to any one of claims 25 to 48, in which the condenser module is arranged to condense steam from the turbine exhaust stream at about atmospheric pressure or above.

50. A steam power system according to any one of claims 25 to 49, in which the steam generator comprises a heat exchange network including a plurality of heat exchange stages arranged sequentially to input heat to the feedwater in ascending order of feedwater temperature, thereby to raise the feedwater temperature from at or below its condensation temperature to at least its critical temperature by means of regenerative heat exchange

51. A steam power system according to claim 50, in which the heat exchange stages are arranged to transfer to the feedwater:

(b) latent heat of condensation of the bleed steam;

(c) sensible heat of the bleed steam condensate; and

52. A steam power system according to claim 50 or claim 51, in which for heat exchange stages that comprise multiple heat exchangers, it is arranged that the feedwater passes through each such heat exchange stage in a plurality of flow paths, wherein a flow path in each such heat exchange stage is dedicated to sensible heat transfer from the turbine exhaust stream to the feedwater, and wherein such heat transfer from the turbine exhaust stream to the feedwater occurs in parallel with transfer to the feedwater of:

(b) latent heat of condensation of the bleed steam; and

(c) sensible heat of the bleed steam condensate;

53. A steam power system according to claim 51, in which the heat exchange stages are arranged to:

(b) raise feedwater steam temperature from the critical temperature to a superheat temperature using sensible heat from turbine bleed stream(s) above the turbine exhaust exit temperature.

54. A steam power system according to any one of claims 50, 51, and 53, as dependent from claim 47, in which the steam generator comprises:

(a) a first stage of heat exchange, in which latent heat from condensation of all three bleed streams is input to the feedwater, together with sensible heat from the condensates of the high and medium pressure bleed streams;

(b) a second stage of heat exchange, in which latent heat from condensation of the high and medium pressure bleed streams is input to the feedwater, together with sensible heat from the low pressure bleed stream above its condensation temperature, but below the turbine exhaust exit temperature, and sensible heat from condensate of the high pressure bleed stream;

(c) a third stage of heat exchange, in which latent heat from condensation of the high pressure bleed stream is input to the feedwater, together with sensible heat from the low and medium pressure bleed streams above their condensation temperatures, but below the turbine exhaust exit temperature;

(d) a fourth stage of heat exchange, in which sensible heat is input to the feedwater from the high, medium and low pressure bleed streams above their condensation temperatures, but below the turbine exhaust exit temperature; (e) a fifth stage of heat exchange, in which sensible heat is input to the feedwater from the high, medium and low pressure bleed streams above the turbine exhaust exit temperature; wherein, in each of the above heat exchange stages, sensible heat from the turbine exhaust stream is also input to the feedwater.

55. A steam power system according to claim 53 or 54, wherein the last stage of heat exchange first adds the bleed stream heat above the turbine exhaust exit temperature to the turbine exhaust stream and then transfers the added heat in the turbine exhaust stream to the feedwater.

56. A steam power system according to any one of claims 50, 51 and 53 to 55, in which each heat input to the feedwater in each heat exchange stage is made in parallel with all other heat inputs to the feedwater in the same heat exchange stage.

57. A steam power system according to any one of claims 43 to 47 and claims 50 to 56 as dependent on claims 43 to 47, in which the high pressure turbine bleed stream is replaced by steam extracted from the steam generator and superheated by one or more other turbine bleed streams while their temperatures are above the turbine exit temperature.

58. A steam power system according to any one of claims 43 to 47 and claims 50 to 56 as dependent on claims 43 to 47, in which the high pressure turbine bleed stream is eliminated and the heat contributed to the feedwater by the high pressure turbine bleed stream is replaced by heat rejected from an air separation unit, said rejected heat being input to the feedwater through the steam generator.

59. A method according to any one of claims 12 to 16 and claims 19 to 24 as dependent on claims 12 to 16, comprising the step of replacing the high pressure turbine bleed stream by steam extracted from the steam generator and superheated by one or more other turbine bleed streams while their temperatures are above the turbine exit temperature.

60. A method according to any one of claims 12 to 16 and claims 19 to 24 as dependent on claims 12 to 16, comprising the steps of eliminating the high pressure turbine bleed stream and replacing the heat contributed to the feedwater by the high pressure turbine bleed stream by heat rejected from an air separation unit, said rejected heat being input to the feedwater through the steam generator.